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Subpart A—General Provisions

§98.1 Purpose and Scope.

(a) This part establishes mandatory greenhouse gas 

(GHG) reporting requirements for owners and operators of 

certain facilities that directly emit GHG as well as for 

certain fossil fuel suppliers and industrial GHG suppliers. 

For suppliers, the GHGs reported are the quantity that 

would be emitted from combustion or use of the products 

supplied.

(b) Owners and operators of facilities and suppliers 

that are subject to this part must follow the requirements 

of subpart A and all applicable subparts of this part. If 

a conflict exists between a provision in subpart A and any 

other applicable subpart, the requirements of the subparts 

B through PP of this part shall take precedence.

§98.2 Who must report?

(a) The GHG reporting requirements and related 

monitoring, recordkeeping, and reporting requirements of 

this part apply to the owners and operators of any facility 

that is located in the United States and that meets the 

requirements of either paragraph (a)(1), (a)(2), or (a)(3) 

of this section; and any supplier that meets the 

requirements of paragraph (a)(4) of this section:
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(1) A facility that contains any source category (as 

defined in subparts C through JJ of this part) that is 

listed in this paragraph (a)(1) in any calendar year 

starting in 2010. For these facilities, the annual GHG 

report must cover all source categories and GHGs for which 

calculation methodologies are provided in subparts C 

through JJ of this part.

(i) Electricity generation (units that report CO2 

emissions year-round through 40 CFR part 75).

(ii) Adipic acid production.

(iii) Aluminum production. 

(iv) Ammonia manufacturing.

(v) Cement production.

(vi) HCFC-22 production.

(vii) HFC-23 destruction processes that are not 

collocated with a HCFC-22 production facility and that 

destroy more than 2.14 metric tons of HFC-23 per year.

(viii) Lime manufacturing.

(ix) Nitric acid production.

(x) Petrochemical production.

(xi) Petroleum refineries.

(xii) Phosphoric acid production.

(xiii) Silicon carbide production.

(xiv) Soda ash production.
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(xv) Titanium dioxide production.

(xvi) Municipal solid waste landfills that generate 

CH4 in amounts equivalent to 25,000 metric tons CO2e or more 

per year, as determined according to subpart HH of this 

part. 

(xvii) Manure management systems with combined CH4 and 

N2O emissions in amounts equivalent to 25,000 metric tons 

CO2e or more per year, as determined according to subpart JJ 

of this part.

(2) A facility that contains any source category (as 

defined in subparts C through JJ of this part) that is 

listed in this paragraph (a)(2) in any calendar year 

starting in 2010 and that emits 25,000 metric tons CO2e or 

more per year in combined emissions from stationary fuel 

combustion units, miscellaneous uses of carbonate, and all 

source categories that are listed in this paragraph. For 

these facilities, the annual GHG report must cover all 

source categories and GHGs for which calculation 

methodologies are provided in subparts C through JJ of this 

part.

(i) Ferroalloy Production.

(ii) Glass Production.

(iii) Hydrogen Production.

(iv) Iron and Steel Production.
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(v) Lead Production.

(vi) Pulp and Paper Manufacturing.

(vii) Zinc Production.

(3) A facility that in any calendar year starting in 

2010 meets all three of the conditions listed in this 

paragraph (a)(3). For these facilities, the annual GHG 

report must cover emissions from stationary fuel combustion 

sources only. 

(i) The facility does not meet the requirements of 

either paragraph (a)(1) or (a)(2) of this section.

(ii) The aggregate maximum rated heat input capacity 

of the stationary fuel combustion units at the facility is 

30 mmBtu/hr or greater.

(iii) The facility emits 25,000 metric tons CO2e or 

more per year in combined emissions from all stationary 

fuel combustion sources.

(4) A supplier (as defined in subparts KK through PP 

of this part) that provides products listed in this 

paragraph (a)(4) in any calendar year starting in 2010. 

For these suppliers, the annual GHG report must cover all 

applicable products for which calculation methodologies are 

provided in subparts KK through PP of this part.

(i) Coal-to-liquids suppliers, as specified in this 

paragraph (i).
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(A) All producers of coal-to-liquid products.

(B) Importers of an annual quantity of coal-to-liquid 

products that is equivalent to 25,000 metric tons CO2e or 

more.

(C) Exporters of an annual quantity of coal-to-liquid 

products is equivalent to 25,000 metric tons CO2e or more.

(ii) Petroleum product suppliers, as specified in 

this paragraph (ii):

(A) All petroleum refineries that distill crude oil.

(B) Importers of an annual quantity of petroleum 

products that is equivalent to 25,000 metric tons CO2e or 

more.

(C) Exporters of an annual quantity of petroleum 

products that is equivalent to 25,000 metric tons CO2e or 

more.

(iii) Natural gas and natural gas liquids suppliers, 

as specified in this paragraph (iii): 

(A) All natural gas fractionators.

(B) Local natural gas distribution companies that 

deliver 460,000 thousand standard cubic feet or more of 

natural gas per year.

(iv) Industrial greenhouse gas suppliers, as 

specified in this paragraph (iv):

(A) All producers of industrial greenhouse gases.
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(B) Importers of industrial greenhouse gases with 

annual bulk imports of N2O, fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 metric tons CO2e or 

more.

(C) Exporters of industrial greenhouse gases with 

annual bulk exports of N2O, fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 metric tons CO2e or 

more.

(v) Carbon dioxide suppliers, as specified in this 

paragraph (v).

(A) All producers of CO2.

(B) Importers of CO2 with annual bulk imports of N2O, 

fluorinated GHG, and CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more.

(C) Exporters of CO2 with annual bulk exports of N2O, 

fluorinated GHG, and CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more.

(5) Research and development activities are not 

considered to be part of any source category defined in 

this part. 

(b) To calculate GHG emissions for comparison to the 

25,000 metric ton CO2e per year emission threshold in 

paragraph (a)(2) of this section, the owner or operator 
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shall calculate annual CO2e emissions, as described in 

paragraphs (b)(1) through (b)(4) of this section. 

(1) Calculate the annual emissions of CO2, CH4, 

N2O,and each fluorinated GHG in metric tons from all 

applicable source categories listed in paragraph (a)(2) of 

this section. The GHG emissions shall be calculated using 

the calculation methodologies specified in each applicable 

subpart and available company records. Include emissions 

from only those gases listed in Table A-1 of this subpart. 

(2) For each general stationary fuel combustion unit, 

calculate the annual CO2 emissions in metric tons using any 

of the four calculation methodologies specified in 

§98.33(a). Calculate the annual CH4 and N2O emissions from 

the stationary fuel combustion sources in metric tons using 

the appropriate equation in §98.33(c). Exclude carbon 

dioxide emissions from the combustion of biomass, but 

include emissions of CH4 and N2O from biomass combustion. 

(3) For miscellaneous uses of carbonate, calculate 

the annual CO2 emissions in metric tons using the procedures 

specified in subpart U of this part.

(4) Sum the emissions estimates from paragraphs 

(b)(1), (b)(2), and (b)(3) of this section for each GHG and 

calculate metric tons of CO2e using Equation A-1 of this 

section.
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





n

i 1 i

x GWP ie GHG 2CO (Eq. A-1)

Where: 

CO2e = Carbon dioxide equivalent, metric tons/year.

GHGi = Mass emissions of each greenhouse gas listed in 

Table A-1 of this subpart, metric tons/year. 

GWPi = Global warming potential for each greenhouse gas 

from Table A-1 of this subpart. 

n = The number of greenhouse gases emitted.

(5) For purpose of determining if an emission 

threshold has been exceeded, include in the emissions 

calculation any CO2 that is captured for transfer off site.

(c) To calculate GHG emissions for comparison to the 

25,000 metric ton CO2e/year emission threshold for 

stationary fuel combustion under paragraph (a)(3) of this 

section, calculate CO2, CH4, and N2O emissions from each 

stationary fuel combustion unit by following the methods 

specified in paragraph (b)(2) of this section. Then, 

convert the emissions of each GHG to metric tons CO2e per 

year using Equation A-1 of this section, and sum the 

emissions for all units at the facility.

(d) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2 per year threshold for importers and 

exporters of coal-to-liquid products under paragraph 

(a)(4)(i) of this section, calculate the mass in metric 

tons per year of CO2 that would result from the complete 
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combustion or oxidation of the quantity of coal-to-liquid 

products that are imported during the reporting year and 

that are exported during the reporting year. Calculate the 

emissions using the methodology specified in subpart LL of 

this part.

(e) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold for importers and 

exporters of petroleum products under paragraph (a)(4)(ii) 

of this section, calculate the mass in metric tons per year 

of CO2 that would result from the complete combustion or 

oxidation of the volume of petroleum products and natural 

gas liquids that are imported during the reporting year and 

that are exported during the reporting year. Calculate the 

emissions using the methodology specified in subpart MM of 

this part.

(f) To calculate GHG quantities for comparison to the 

25,000 metric ton CO2e per year threshold under paragraph 

(a)(4) of this section for importers and exporters of 

industrial greenhouse gases and for importers and exporters 

of CO2, the owner or operator shall calculate the mass in 

metric tons per year of CO2e imports and exports as 

described in paragraphs (f)(1) through (f)(3) of this 

section. 
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(1) Calculate the mass in metric tons per year of CO2, 

N2O, and each fluorinated GHG that is imported and the mass 

in metric tons per year of CO2, N2O, and each fluorinated 

GHG that is exported during the year. Include only those 

gases listed in Table A-1 of this subpart. 

(2) Convert the mass of each imported and each GHG 

exported from paragraph (f)(1) of this section to metric 

tons of CO2e using Equation A-1 of this section.

(3) Sum the total annual metric tons of CO2e in 

paragraph (f)(2) of this section for all imported GHGs. 

Sum the total annual metric tons of CO2e in paragraph (f)(2) 

of this section for all exported GHGs. 

(g) If a capacity or generation reporting threshold 

in paragraph (a)(1) of this section applies, the owner or 

operator shall review the appropriate records and perform 

any necessary calculations to determine whether the 

threshold has been exceeded. 

(h) An owner or operator of a facility or supplier 

that does not meet the applicability requirements of 

paragraph (a) of this section is not subject to this rule. 

Such owner or operator would become subject to the rule and 

reporting requirements §98.3(b)(3), if a facility or 

supplier exceeds the applicability requirements of 

paragraph (a) of this section at a later time. Thus, the 
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owner or operator should reevaluate the applicability to 

this part (including the revising of any relevant emissions 

calculations or other calculations) whenever there is any 

change that could cause a facility or supplier to meet the 

applicability requirements of paragraph (a) of this 

section. Such changes include but are not limited to 

process modifications, increases in operating hours, 

increases in production, changes in fuel or raw material 

use, addition of equipment, and facility expansion.

(i) Except as provided in this paragraph, once a 

facility or supplier is subject to the requirements of this 

part, the owner or operator must continue for each year 

thereafter to comply with all requirements of this part, 

including the requirement to submit annual GHG reports, 

even if the facility or supplier does not meet the 

applicability requirements in paragraph (a) of this section 

in a future year.

(1) If reported emissions are less than 25,000 metric 

tons CO2e per year for five consecutive years, then the 

owner or operator may discontinue complying with this part 

provided that the owner or operator submits a notification 

to the Administrator that announces the cessation of 

reporting and explains the reasons for the reduction in 

emissions. The notification shall be submitted no later 
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than March 31 of the year immediately following the fifth 

consecutive year of emissions less than 25,000 tons CO2e per 

year. The owner or operator must maintain the 

corresponding records required under §98.3(g) for each of 

the five consecutive years and retain such records for 

three years following the year that reporting was 

discontinued. The owner or operator must resume reporting 

if annual emissions in any future calendar year increase to 

25,000 metric tons CO2e per year or more.

(2) If reported emissions are less than 15,000 metric 

tons CO2e per year for three consecutive years, then the 

owner or operator may discontinue complying with this part 

provided that the owner or operator submits a notification 

to the Administrator that announces the cessation of 

reporting and explains the reasons for the reduction in 

emissions. The notification shall be submitted no later 

than March 31 of the year immediately following the third 

consecutive year of emissions less than 15,000 tons CO2e per 

year. The owner or operator must maintain the 

corresponding records required under §98.3(g) for each of 

the three consecutive years and retain such records for 

three years following the year that reporting was 

discontinued. The owner or operator must resume reporting 
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if annual emissions in any future calendar year increase to 

25,000 metric tons CO2e per year or more.

(3) If the operations of a facility or supplier are 

changed such that all applicable GHG-emitting processes and 

operations listed in paragraphs (a)(1) through (a)(4) of 

this section cease to operate, then the owner or operator 

is exempt from reporting in the years following the year in 

which cessation of such operations occurs, provided that 

the owner or operator submits a notification to the 

Administrator that announces the cessation of reporting and 

certifies to the closure of all GHG-emitting processes and 

operations. This paragraph (i)(2) does not apply to 

seasonal or other temporary cessation of operations. This 

paragraph (i)(2) does not apply to facilities with 

municipal solid waste landfills. The owner or operator 

must resume reporting for any future calendar year during 

which any of the GHG-emitting processes or operations 

resume operation.

(j) Table A-2 of this subpart provides a conversion 

table for some of the common units of measure used in part 

98.

§98.3 What are the general monitoring, reporting, 

recordkeeping and verification requirements of this part?
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The owner or operator of a facility or supplier that 

is subject to the requirements of this part must submit GHG 

reports to the Administrator, as specified in this section.

(a) General. Except as provided in paragraph (d) of 

this section, follow the procedures for emission 

calculation, monitoring, quality assurance, missing data, 

recordkeeping, and reporting that are specified in each 

relevant subpart of this part.

(b) Schedule. The annual GHG report must be 

submitted no later than March 31 of each calendar year for 

GHG emissions in the previous calendar year.

(1) For an existing facility or supplier that began 

operation before January 1, 2010, report emissions for 

calendar year 2010 and each subsequent calendar year.

(2) For a new facility or supplier that begins 

operation on or after January 1, 2010, report emissions 

beginning with the first operating month and ending on 

December 31 of that year. Each subsequent annual report 

must cover emissions for the calendar year, beginning on 

January 1 and ending on December 31.

(3) For any facility or supplier that becomes subject 

to this rule because of a physical or operational change 

that is made after January 1, 2010, report emissions for 

the first calendar year in which the change occurs, 
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beginning with the first month of the change and ending on 

December 31 of that year. For a facility or supplier that

becomes subject to this rule solely because of an increase 

in hours of operation or level of production, the first 

month of the change is the month in which the increased 

hours of operation or level of production, if maintained 

for the remainder of the year, would cause the facility or 

supplier to exceed the applicable threshold. Each 

subsequent annual report must cover emissions for the

calendar year, beginning on January 1 and ending on 

December 31.

(c) Content of the annual report. Except as provided 

in paragraph (d) of this section, each annual GHG report 

shall contain the following information:

(1) Facility name or supplier name (as appropriate), 

facility or supplier ID number, and physical street address 

of the facility or supplier, including the city, state, and 

zip code.

(2) Year and months covered by the report.

(3) Date of submittal.

(4) For facilities, report annual emissions of CO2, 

CH4, N2O, and each fluorinated GHG (as defined in §98.6) as 

follows:
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(i) Annual emissions (including biogenic CO2) 

aggregated for all GHG from all applicable source 

categories in subparts C through JJ of this part and 

expressed in metric tons of CO2e calculated using Equation 

A-1 of this subpart.

(ii) Annual emissions of biogenic CO2 aggregated for 

all applicable source categories in subparts C through JJ 

of this part in metric tons. Units that use the 

methodologies in part 75 of this chapter to calculate CO2

mass emissions are not required to separately report 

biogenic CO2 emissions, but may do so as an option.

(iii) Annual emissions from each applicable source 

category in subparts C through JJ of this part, expressed 

in metric tons of each applicable GHG listed in this 

paragraph (4)(iii)(A) through (4)(iii)(E). 

(A) Biogenic CO2. Units that use the methodologies in 

part 75 of this chapter to calculate CO2 mass emissions are 

not required to separately report biogenic CO2 emissions,

but may do so as an option.

(B) CO2 (including biogenic CO2).

(C) CH4.

(D) N2O.

(E) Each fluorinated GHG (including those not listed 

in Table A-1 of this subpart).
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(iv) Emissions and other data for individual units. 

processes, activities, and operations as specified in the 

“Data reporting requirements” section of each applicable 

subpart of this part.

(5) For suppliers, report annual quantities of CO2, 

CH4, N2O, and each fluorinated GHG (as defined in §98.6) that 

would be emitted from combustion or use of the products 

supplied, imported, and exported during the year. Calculate 

and report quantities at the following levels:

(i) Total quantity of GHG aggregated for all GHG from 

all applicable supply categories in subparts KK through PP 

of this part and expressed in metric tons of CO2e calculated 

using Equation A-1 of this subpart. For fluorinated GHGs, 

calculate and report CO2e for only those fluorinated GHGs 

listed in Table A-1 of this subpart.

(ii) Quantity of each GHG from each applicable supply 

category in subparts KK through PP of this part, expressed 

in metric tons of each GHG. For fluorinated GHG, report 

emissions of all fluorinated GHG, including those not 

listed in Table A-1 of this subpart.

(iii) Any other data specified in the “Data reporting 

requirements” section of each applicable subpart of this 

part. 
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(6) A written explanation, as required under 

§98.3(e), if you change emission calculation methodologies 

during the reporting period.

(7) A brief description of each “best available 

monitoring method” used according to paragraph (d) of this 

section, the parameter measured using the method, and the 

time period during which the “best available monitoring 

method” was used.

(8) Each data element for which a missing data 

procedure was used according to the procedures of an 

applicable subpart and the total number of hours in the 

year that a missing data procedure was used for each data 

element.

(9) A signed and dated certification statement 

provided by the designated representative of the owner or 

operator, according to the requirements of §98.4(e)(1).

(d) Special provisions for reporting year 2010.

(1) Best available monitoring methods. During 

January 1, 2010 through March 31, 2010, owners or operators 

may use best available monitoring methods for any parameter 

(e.g., fuel use, daily carbon content of feedstock by 

process line) that cannot reasonably be measured according 

to the monitoring and QA/QC requirements of a relevant 

subpart. The owner or operator must use the calculation 
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methodologies and equations in the “Calculating GHG 

Emissions” sections of each relevant subpart, but may use 

the best available monitoring method for any parameter for 

which it is not reasonably feasible to acquire, install, 

and operate a required piece of monitoring equipment by 

January 1, 2010. Starting no later than April 1, 2010, the 

owner or operator must discontinue using best available 

methods and begin following all applicable monitoring and 

QA/QC requirements of this part, except as provided in

paragraphs (d)(2) and (d)(3) of this section. Best 

available monitoring methods means any of the following 

methods specified in this paragraph:

(i) Monitoring methods currently used by the facility 

that do not meet the specifications of an relevant subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

(2) Requests for extension of the use of best 

available monitoring methods. The owner or operator may 

submit a request to the Administrator to use one or more 

best available monitoring methods beyond March 31, 2010.

(i) Timing of request. The extension request must be 

submitted to EPA no later than 30 days after the effective 

date of the GHG reporting rule.
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(ii) Content of request. Requests must contain the 

following information:

(A) A list of specific item of monitoring 

instrumentation for which the request is being made and the 

locations where each piece of monitoring instrumentation 

will be installed.

(B) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) for which 

the instrumentation is needed. 

(C) A description of the reasons why the needed 

equipment could not be obtained and installed before April 

1, 2010.

(D) If the reason for the extension is that the 

equipment cannot be purchased and delivered by April 1, 

2010, include supporting documentation such as the date the 

monitoring equipment was ordered, investigation of 

alternative suppliers and the dates by which alternative 

vendors promised delivery, backorder notices or unexpected 

delays, descriptions of actions taken to expedite delivery, 

and the current expected date of delivery.

(E) If the reason for the extension is that the 

equipment cannot be installed without a process unit 

shutdown, include supporting documentation demonstrating 

that it is not practicable to isolate the equipment and 
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install the monitoring instrument without a full process 

unit shutdown. Include the date of the most recent process 

unit shutdown, the frequency of shutdowns for this process 

unit, and the date of the next planned shutdown during 

which the monitoring equipment can be installed. If there 

has been a shutdown or if there is a planned process unit 

shutdown between promulgation of this part and April 1, 

2010, include a justification of why the equipment could 

not be obtained and installed during that shutdown.

(F) A description of the specific actions the 

facility will take to obtain and install the equipment as 

soon as reasonably feasible and the expected date by which 

the equipment will be installed and operating. 

(iii) Approval Criteria. To obtain approval, the 

owner or operator must demonstrate to the Administrator’s 

satisfaction that it is not reasonably feasible to acquire, 

install, and operate a required piece of monitoring 

equipment by April 1, 2010. The use of best available 

methods will not be approved beyond December 31, 2010.

(3) Abbreviated emissions report for facilities 

containing only general stationary fuel combustion sources. 

In lieu of the report required by paragraph (c) of this 

section, the owner or operator of an existing facility that 

is in operation on January 1, 2010 and that meets the 
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conditions of §98.2 (a)(3) may submit an abbreviated GHG 

report for the facility for GHGs emitted in 2010. The 

abbreviated report must be submitted by March 31, 2011. An 

owner or operator that submits an abbreviated report must 

submit a full GHG report according to the requirements of 

paragraph (c) of this section beginning in calendar year

2012. The abbreviated facility report must include the 

following information:

(i) Facility name and physical street address 

including the city, state and zip code.

(ii) The year and months covered by the report.

(iii) Date of submittal.

(iv) Total facility GHG emissions aggregated for all 

stationary fuel combustion units calculated according to 

any method specified in §98.33(a) and expressed in metric 

tons of CO2, CH4, N2O, and CO2e. 

(v) Any facility operating data or process 

information used for the GHG emission calculations. 

(vi) A signed and dated certification statement 

provided by the designated representative of the owner or 

operator, according to the requirements of paragraph (e)(1) 

of this section.

(e) Emission Calculations. In preparing the GHG 

report, you must use the calculation methodologies 
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specified in the relevant subparts, except as specified in 

paragraph (d) of this section. For each source category, 

you must use the same calculation methodology throughout a 

reporting period unless you provide a written explanation 

of why a change in methodology was required. 

(f) Verification. To verify the completeness and 

accuracy of reported GHG emissions, the Administrator may 

review the certification statements described in paragraphs 

(c)(9) and (d)(3)(vi) of this section and any other 

credible evidence, in conjunction with a comprehensive 

review of the GHG reports and periodic audits of selected 

reporting facilities. Nothing in this section prohibits 

the Administrator from using additional information to 

verify the completeness and accuracy of the reports.

(g) Recordkeeping. An owner or operator that is 

required to report GHGs under this part must keep records 

as specified in this paragraph. Retain all required 

records for at least 3 years. The records shall be kept in 

an electronic or hard-copy format (as appropriate) and 

recorded in a form that is suitable for expeditious 

inspection and review. Upon request by the Administrator, 

the records required under this section must be made 

available to EPA. Records may be retained off site if the 

records are readily available for expeditious inspection 
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and review. For records that are electronically generated 

or maintained, the equipment or software necessary to read 

the records shall be made available, or, if requested by 

EPA, electronic records shall be converted to paper 

documents. You must retain the following records, in 

addition to those records prescribed in each applicable 

subpart of this part:

(1) A list of all units, operations, processes, and 

activities for which GHG emission were calculated.

(2) The data used to calculate the GHG emissions for 

each unit, operation, process, and activity, categorized by 

fuel or material type. These data include but are not 

limited to the following information in this paragraph 

(g)(2):

(i) The GHG emissions calculations and methods used.

(ii) Analytical results for the development of sitespecific emissions factors.

(iii) The results of all required analyses for high 

heat value, carbon content, and other required fuel or 

feedstock parameters.

(iv) Any facility operating data or process 

information used for the GHG emission calculations.

(3) The annual GHG reports.
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(4) Missing data computations. For each missing data 

event, also retain a record of the cause of the event and 

the corrective actions taken to restore malfunctioning 

monitoring equipment.

(5) A written GHG Monitoring Plan. 

(i) At a minimum, the GHG Monitoring Plan shall 

include the elements listed in this paragraph (i).

(A) Identification of positions of responsibility 

(i.e., job titles) for collection of the emissions data.

(B) Explanation of the processes and methods used to 

collect the necessary data for the GHG calculations.

(C) Description of the procedures and methods that 

are used for quality assurance, maintenance, and repair of 

all continuous monitoring systems, flow meters, and other 

instrumentation used to provide data for the GHGs reported 

under this part.

(ii) The GHG Monitoring Plan may rely on references 

to existing corporate documents (e.g., standard operating 

procedures, quality assurance programs under appendix F to 

40 CFR part 60 or appendix B to 40 CFR part 75, and other 

documents) provided that the elements required by paragraph 

(g)(5)(i) of this section are easily recognizable.

(iii) The owner or operator shall revise the GHG 

Monitoring Plan as needed to reflect changes in production 
26

processes, monitoring instrumentation, and quality 

assurance procedures; or to improve procedures for the 

maintenance and repair of monitoring systems to reduce the 

frequency of monitoring equipment downtime. 

(iv) Upon request by the Administrator, the owner or 

operator shall make all information that is collected in 

conformance with the GHG Monitoring Plan available for 

review during an audit. Electronic storage of the 

information in the plan is permissible, provided that the 

information can be made available in hard copy upon request 

during an audit.

(6) The results of all required certification and 

quality assurance tests of continuous monitoring systems, 

fuel flow meters, and other instrumentation used to provide 

data for the GHGs reported under this part.

(7) Maintenance records for all continuous monitoring 

systems, flow meters, and other instrumentation used to 

provide data for the GHGs reported under this part.

(h) Annual GHG report revisions. 

(1) The owner or operator shall submit a revised 

annual GHG report within 45 days of discovering that an 

annual GHG report that the owner or operator previously 

submitted contains one or more substantive errors. The 

revised report must correct all substantive errors. 
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(2) The Administrator may notify the owner or 

operator in writing that an annual GHG report previously 

submitted by the owner or operator contains one or more 

substantive errors. Such notification will identify each 

such substantive error. The owner or operator shall, 

within 45 days of receipt of the notification, either 

resubmit the report that, for each identified substantive 

error, corrects the identified substantive error (in 

accordance with the applicable requirements of this part) 

or provide information demonstrating that the previously 

submitted report does not contain the identified 

substantive error or that the identified error is not a 

substantive error. 

(3) A substantive error is an error that impacts the 

quantity of GHG emissions reported or otherwise prevents 

the reported data from being validated or verified.

(4) Notwithstanding paragraphs (h)(1) and (h)(2) of 

this section, upon request by the owner or operator, the 

Administrator may provide reasonable extensions of the 45-

day period for submission of the revised report or 

information under paragraphs (h)(1) and (h)(2) of this 

section. If the Administrator receives a request for 

extension of the 45-day period, by e-mail to an address 

prescribed by the Administrator, at least two business days 
28

prior to the expiration of the 45-day period, and the 

Administrator does not respond to the request by the end of 

such period, the extension request is deemed to be 

automatically granted for 30 more days. During the 

automatic 30-day extension, the Administrator will 

determine what extension, if any, beyond the automatic 

extension is reasonable and will provide any such 

additional extension.

(5) The owner or operator shall retain documentation 

for 3 years to support any revision made to an annual GHG 

report. 

(i) Calibration and accuracy requirements. The owner 

or operator of a facility or supplier that is subject to 

the requirements of this part must meet the applicable flow 

meter calibration and accuracy requirements of this 

paragraph (i). The accuracy specifications in this 

paragraph (i) do not apply where either the use of company 

records (as defined in §98.6) or the use of “best available 

information” is specified in an applicable subpart of this 

part to quantify fuel usage and/or other parameters. 

Further, the provisions of this paragraph (i) do not apply 

to stationary fuel combustion units that use the 

methodologies in part 75 of this chapter to calculate CO2

mass emissions.
29

(1) Except as otherwise provided in paragraphs (i)(4) 

through (i)(6) of this section, flow meters that measure 

liquid and gaseous fuel feed rates, process stream flow 

rates, or feedstock flow rates and provide data for the GHG

emissions calculations, shall be calibrated prior to April 

1, 2010 using the procedures specified in this paragraph

(i) when such calibration is specified in a relevant 

subpart of this part. Each of these flow meters shall meet 

the applicable accuracy specification in paragraph (i)(2) 

or (i)(3) of this section. All other measurement devices 

(e.g., weighing devices) that are required by a relevant 

subpart of this part, and that are used to provide data for 

the GHG emissions calculations, shall also be calibrated 

prior to April 1, 2010; however, the accuracy 

specifications in paragraphs (i)(2) and (i)(3) of this 

section do not apply to these devices. Rather, each of 

these measurement devices shall be calibrated to meet the 

accuracy requirement specified for the device in the 

applicable subpart of this part, or, in the absence of such 

accuracy requirement, the device must be calibrated to an 

accuracy within the appropriate error range for the 

specific measurement technology, based on an applicable 

operating standard, including but not limited to industry 

standards and manufacturer’s specifications. The 
30

procedures and methods used to quality-assure the data from 

each measurement device shall be documented in the written 

Monitoring Plan, pursuant to paragraph (g)(5)(i)(C) of this 

section.

(i) All flow meters and other measurement devices

that are subject to the provisions of this paragraph (i) 

must be calibrated according to one of the following. You 

may use the manufacturer’s recommended procedures; an 

appropriate industry consensus standard method; or a method 

specified in a relevant subpart of this part. The 

calibration method(s) used shall be documented in the 

Monitoring Plan required under paragraph (g) of this 

section. 

(ii) For facilities and suppliers that become subject 

to this part after April 1, 2010, all flow meters and other 

measurement devices (if any) that are required by the 

relevant subpart(s) of this part to provide data for the 

GHG emissions calculations shall be installed no later than 

the date on which data collection is required to begin

using the measurement device, and the initial 

calibration(s) required by this paragraph (i) (if any) 

shall be performed no later than that date. 

(iii) Except as otherwise provided in paragraphs 

(i)(4) through (i)(6) of this section, subsequent 
31

recalibrations of the flow meters and other measurement 

devices subject to the requirements of this paragraph (i) 

shall be performed at one of the following frequencies:

(A) You may use the frequency specified in each 

applicable subpart of this part.

(B) You may use the frequency recommended by the 

manufacturer or by an industry consensus standard practice, 

if no recalibration frequency is specified in an applicable 

subpart.

(2) Perform all flow meter calibration at measurement 

points that are representative of the normal operating

range of the meter. Except for the orifice, nozzle, and 

venturi flow meters described in paragraph (i)(3) of this 

section, calculate the calibration error at each 

measurement point using Equation A-2 of this section. The 

terms “R” and “A” in Equation A-2 must be expressed in 

consistent units of measure (e.g., gallons/minute, ft3/min). 

The calibration error at each measurement point shall not 

exceed 5.0 percent of the reference value.

x 100

R

R A

CE



 (Eq. A-2)

Where:

CE = Calibration error (%)
32

R = Reference value 

A = Flow meter response to the reference value

(3) For orifice, nozzle, and venturi flow meters, the 

initial quality assurance consists of in-situ calibration 

of the differential pressure (delta-P), total pressure, and 

temperature transmitters. 

(i) Calibrate each transmitter at a zero point and at 

least one upscale point. Fixed reference points, such as 

the freezing point of water, may be used for temperature 

transmitter calibrations. Calculate the calibration error 

of each transmitter at each measurement point, using 

Equation A-3 of this subpart. The terms “R”, “A”, and “FS” 

in Equation A-3 of this subpart must be in consistent units 

of measure (e.g., milliamperes, inches of water, psi, 

degrees). For each transmitter, the CE value at each 

measurement point shall not exceed 2.0 percent of fullscale. Alternatively, the results are acceptable if the 

sum of the calculated CE values for the three transmitters 

at each calibration level (i.e., at the zero level and at 

each upscale level) does not exceed: 6.0 percent.

x 100

FS

R A

CE



 (Eq. A-3)

Where:
33

CE = Calibration error (%)

R = Reference value 

A = Transmitter response to the reference value

FS = Full-scale value of the transmitter

(ii) In cases where there are only two transmitters 

(i.e., differential pressure and either temperature or 

total pressure) in the immediate vicinity of the flow 

meter’s primary element (e.g., the orifice plate), or when 

there is only a differential pressure transmitter in close 

proximity to the primary element, calibration of these 

existing transmitters to a CE of 2.0 percent or less at 

each measurement point is still required, in accordance 

with paragraph (i)(3)(i) of this section; alternatively, 

when two transmitters are calibrated, the results are 

acceptable if the sum of the CE values for the two 

transmitters at each calibration level does not exceed 4.0 

percent. However, note that installation and calibration 

of an additional transmitter (or transmitters) at the flow 

monitor location to measure temperature or total pressure 

or both is not required in these cases. Instead, you may 

use assumed values for temperature and/or total pressure, 

based on measurements of these parameters at a remote 

location (or locations), provided that the following 

conditions are met:
34

(A) You must demonstrate that measurements at the 

remote location(s) can, when appropriate correction factors 

are applied, reliably and accurately represent the actual 

temperature or total pressure at the flow meter under all 

expected ambient conditions.

(B) You must make all temperature and/or total 

pressure measurements in the demonstration described in 

paragraph (i)(3)(ii)(A) of this section with calibrated 

gauges, sensors, transmitters, or other appropriate 

measurement devices. At a minimum, calibrate each of these 

devices to an accuracy within the appropriate error range 

for the specific measurement technology, according to one 

of the following. You may calibrate using an industry 

consensus standards or a manufacturer’s specification. 

(C) You must document the methods used for the 

demonstration described in paragraph (i)(3)(ii)(A) of this 

section in the written Monitoring Plan under paragraph 

(g)(5)(i)(C) of this section. You must also include the 

data from the demonstration, the mathematical 

correlation(s) between the remote readings and actual flow 

meter conditions derived from the data, and any supporting 

engineering calculations in the Monitoring Plan. You must 

maintain all of this information in a format suitable for 

auditing and inspection.
35

(D) You must use the mathematical correlation(s)

derived from the demonstration described in paragraph 

(i)(3)(ii)(A) of this section to convert the remote 

temperature or the total pressure readings, or both, to the 

actual temperature or total pressure at the flow meter, or 

both, on a daily basis. You shall then use the actual 

temperature and total pressure values to correct the 

measured flow rates to standard conditions. 

(E) You shall periodically check the correlation(s) 

between the remote and actual readings (at least once a 

year), and make any necessary adjustments to the 

mathematical relationship(s).

(4) Fuel billing meters are exempted from the 

calibration requirements of this section and from the 

Monitoring Plan and recordkeeping provisions of paragraphs

(g)(5)(i)(C) and (g)(7) of this section, provided that the 

fuel supplier and any unit combusting the fuel do not have 

any common owners and are not owned by subsidiaries or 

affiliates of the same company. Meters used exclusively to 

measure the flow rates of fuels that are used for unit 

startup or ignition are also exempted from the calibration 

requirements of this section. 

(5) For a flow meter that has been previously 

calibrated in accordance with paragraph (i)(1) of this 
36

section, an additional calibration is not required by the 

date specified in paragraph (i)(1) of this section if, as 

of that date, the previous calibration is still active 

(i.e., the device is not yet due for recalibration because 

the time interval between successive calibrations has not 

elapsed). In this case, the deadline for the successive 

calibrations of the flow meter shall be set according to 

one of the following. You may use either the 

manufacturer’s recommended calibration schedule or you may 

use the industry consensus calibration schedule. 

(6) For units and processes that operate continuously 

with infrequent outages, it may not be possible to meet the 

April 1, 2010 deadline for the initial calibration of a 

flow meter or other measurement device without disrupting 

normal process operation. In such cases, the owner or 

operator may postpone the initial calibration until the 

next scheduled maintenance outage. The best available 

information from company records may be used in the 

interim. The subsequent required recalibrations of the 

flow meters may be similarly postponed. Such postponements 

shall be documented in the monitoring plan that is required 

under paragraph (g)(5) of this section. 

(7) If the results of an initial calibration or a 

recalibration fail to meet the required accuracy 
37

specification, data from the flow meter shall be considered 

invalid, beginning with the hour of the failed calibration 

and continuing until a successful calibration is completed. 

You shall follow the missing data provisions provided in 

the relavant missing data sections during the period of 

data invalidation.

(j) Measurement Device Installation.

(1) General. If an owner or operator required to 

report under subpart P, subpart X or subpart Y of this part 

has process equipment or units that operate continuously 

and it is not possible to install a required flow meter or 

other measurement device by April 1, 2010, (or by any later 

date in 2010 approved by the Administrator as part of an 

extension of best available monitoring methods per 

paragraph (d) of this section) without process equipment or 

unit shutdown, or through a hot tap, the owner or operator 

may request an extension from the Administrator to delay 

installing the measurement device until the next scheduled 

process equipment or unit shutdown. If approval for such 

an extension is granted by the Administrator, the owner or 

operator must use best available monitoring methods during 

the extension period. 

(2) Requests for extension of the use of best 

available monitoring methods for measurement device 
38

installation. The owner or operator must first provide the 

Administrator an initial notification of the intent to 

submit an extension request for use of best available 

monitoring methods beyond December 31, 2010 (or an earlier 

date approved by EPA) in cases where measurement device 

installation would require a process equipment or unit 

shutdown, or could only be done through a hot tap. The 

owner or operator must follow-up this initial notification 

with the complete extension request containing the 

information specified in paragraph (j)(4) of this section 

below. 

(3) Timing of request. 

(i) The initial notice of intent must be submitted no 

later than January 1, 2011, or by the end of the approved 

use of best available monitoring methods extension in 2010, 

whichever is earlier. The completed extension request must 

be submitted to the Administrator no later than February 

15, 2011. 

(ii) Any subsquent extensions to the original request 

must be submitted to the Administrator within 4 weeks of 

the owner or operator identifying the need to extend the 

request, but in any event no later than 4 weeks before the 

date for the planned process equipment or unit shutdown 

that was provided in the original request. 
39

(4) Content of the request. Requests must contain 

the following information:

(i) Specific measurement device for which the request 

is being made and the location where each measurement 

device will be installed. 

(ii) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) requiring 

the measurement device.

(iii) A description of the reasons why the needed 

equipment could not be installed before April 1, 2010, or 

by the expiration date for the use of best available 

monitoring methods, in cases where an extension has been 

granted under §98.3(d). 

(iv) Supporting documentation showing that it is not 

practicable to isolate the process equipment or unit and 

install the measurement device without a full shutdown or a 

hot tap, and that there was no opportunity during 2010 to 

install the device. Include the date of the three most 

recent shutdowns for each relevant process equipment or 

unit, the frequency of shutdowns for each relevant process 

equipment or unit, and the date of the next planned process 

equipment or unit shutdown. 
40

(v) Include a description of the proposed best 

available monitoring method for estimating GHG emissions 

during the time prior to installation of the meter. 

(5) Approval criteria. The owner or operator must 

demonstrate to the Administrator’s satisfaction that it is 

not reasonably feasible to install the measurement device 

before April 1, 2010 (or by the expiration date for the 

use of best available monitoring methods, in cases where an 

extension has been granted under paragraph (d) of this 

section) without a process equipment or unit shutdown, or 

through a hot tap, and that the proposed method for 

estimating GHG emissions during the time before which the 

measurement device will be installed is appropriate. The 

Administrator will not initially approve the use of the 

proposed best available monitoring method past December 31, 

2013. 

(6) Measurement device installation deadline. Any 

owner or operator that submits both a timely initial notice 

of intent and a timely completed extension request under 

paragraph (j)(3) of this section to extend use of best 

available monitoring methods for measurement device 

installation must install all such devices by July 1, 2011 

unless the extension request under this paragraph (j) is 

approved by the Administrator before July 1, 2011.
41

(7) One time extension past December 31, 2013. If an 

owner or operator determines that a scheduled process 

equipment or unit shutdown will not occur by December 31, 

2013, the owner or operator may re-apply to use best 

available monitoring methods for one additional time 

period, not to extend beyond December 31, 2015. To extend 

use of best available monitoring methods past December 31, 

2013, the owner or operator must submit a new extension 

request by June 1, 2013 that contains the information 

required in paragraph (j)(4) of this section. The owner or 

operator must demonstrate to the Administrator’s 

satisfaction that it continues to not be reasonably 

feasible to install the measurement device before December 

31, 2013 without a process equipment or unit shutdown, or 

that installation of the measurement device could only be 

done through a hot tap, and that the proposed method for 

estimating GHG emissions during the time before which the 

measurement device will be installed is appropriate. An 

owner or operator that submits a request under this 

paragraph to extend use of best available monitoring 

methods for measurement device installation must install 

all such devices by December 31, 2013, unless the extension 

request under this paragraph is approved by the 

Administrator. 
42

§98.4 Authorization and Responsibilities of the Designated 

Representative.

(a) General. Except as provided under paragraph (f) 

of this section, each facility, and each supplier, that is 

subject to this part, shall have one and only one 

designated representative, who shall be responsible for 

certifying, signing, and submitting GHG emissions reports 

and any other submissions for such facility and supplier 

respectively to the Administrator under this part. If the 

facility is required under any other part of title 40 of 

the Code of Federal Regulations to submit to the 

Administrator any other emission report that is subject to 

any requirement in 40 CFR part 75, the same individual 

shall be the designated representative responsible for 

certifying, signing, and submitting the GHG emissions 

reports and all such other emissions reports under this 

part. 

(b) Authorization of a designated representative. 

The designated representative of the facility or supplier 

shall be an individual selected by an agreement binding on 

the owners and operators of such facility or supplier and 

shall act in accordance with the certification statement in

paragraph (i)(4)(iv) of this section. 
43

(c) Responsibility of the designated representative. 

Upon receipt by the Administrator of a complete certificate 

of representation under this section for a facility or 

supplier, the designated representative identified in such 

certificate of representation shall represent and, by his 

or her representations, actions, inactions, or submissions, 

legally bind each owner and operator of such facility or 

supplier in all matters pertaining to this part, 

notwithstanding any agreement between the designated 

representative and such owners and operators. The owners 

and operators shall be bound by any decision or order 

issued to the designated representative by the 

Administrator or a court.

(d) Timing. No GHG emissions report or other 

submissions under this part for a facility or supplier will 

be accepted until the Administrator has received a complete 

certificate of representation under this section for a 

designated representative of the facility or supplier. Such 

certificate of representation shall be submitted at least 

60 days before the deadline for submission of the 

facility’s or supplier’s initial emission report under this 

part.

(e) Certification of the GHG emissions report. Each 

GHG emission report and any other submission under this 
44

part for a facility or supplier shall be certified, signed, 

and submitted by the designated representative or any 

alternate designated representative of the facility or 

supplier in accordance with this section and §3.10.

(1) Each such submission shall include the following 

certification statement signed by the designated 

representative or any alternate designated representative: 

“I am authorized to make this submission on behalf of the 

owners and operators of the facility or supplier, as 

applicable, for which the submission is made. I certify 

under penalty of law that I have personally examined, and 

am familiar with, the statements and information submitted 

in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility 

for obtaining the information, I certify that the 

statements and information are to the best of my knowledge 

and belief true, accurate, and complete. I am aware that 

there are significant penalties for submitting false 

statements and information or omitting required statements 

and information, including the possibility of fine or 

imprisonment.”

(2) The Administrator will accept a GHG emission 

report or other submission for a facility or supplier under 
45

this part only if the submission is certified, signed, and 

submitted in accordance with this section.

(f) Alternate designated representative. A 

certificate of representation under this section for a 

facility or supplier may designate one alternate designated 

representative, who shall be an individual selected by an 

agreement binding on the owners and operators, and may act 

on behalf of the designated representative, of such 

facility or supplier. The agreement by which the alternate 

designated representative is selected shall include a 

procedure for authorizing the alternate designated 

representative to act in lieu of the designated 

representative.

(1) Upon receipt by the Administrator of a complete 

certificate of representation under this section for a 

facility or supplier identifying an alternate designated 

representative.

(i) The alternate designated representative may act 

on behalf of the designated representative for such 

facility or supplier.

(ii) Any representation, action, inaction, or 

submission by the alternate designated representative shall 

be deemed to be a representation, action, inaction, or 

submission by the designated representative.
46

(2) Except in this section, whenever the term 

“designated representative” is used in this part, the term 

shall be construed to include the designated representative 

or any alternate designated representative.

(g) Changing a designated representative or alternate 

designated representative. The designated representative 

or alternate designated representative identified in a 

complete certificate of representation under this section 

for a facility or supplier received by the Administrator 

may be changed at any time upon receipt by the 

Administrator of another later signed, complete certificate 

of representation under this section for the facility or 

supplier. Notwithstanding any such change, all 

representations, actions, inactions, and submissions by the 

previous designated representative or the previous 

alternate designated representative of the facility or 

supplier before the time and date when the Administrator 

receives such later signed certificate of representation 

shall be binding on the new designated representative and 

the owners and operators of the facility or supplier.

(h) Changes in owners and operators. In the event an 

owner or operator of the facility or supplier is not 

included in the list of owners and operators in the 

certificate of representation under this section for the 
47

facility or supplier, such owner or operator shall be 

deemed to be subject to and bound by the certificate of 

representation, the representations, actions, inactions, 

and submissions of the designated representative and any 

alternate designated representative of the facility or 

supplier, as if the owner or operator were included in such 

list. Within 90 days after any change in the owners and 

operators of the facility or supplier (including the 

addition of a new owner or operator), the designated 

representative or any alternate designated representative 

shall submit a certificate of representation that is 

complete under this section except that such list shall be 

amended to reflect the change. If the designated 

representative or alternate designated representative 

determines at any time that an owner or operator of the 

facility or supplier is not included in such list and such 

exclusion is not the result of a change in the owners and 

operators, the designated representative or any alternate 

designated representative shall submit, within 90 days of 

making such determination, a certificate of representation 

that is complete under this section except that such list 

shall be amended to include such owner or operator. 

(i) Certificate of representation. A certificate of 

representation shall be complete if it includes the 
48

following elements in a format prescribed by the 

Administrator in accordance with this section:

(1) Identification of the facility or supplier for 

which the certificate of representation is submitted.

(2) The name, organization name (company affiliationemployer), address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of the 

designated representative and any alternate designated 

representative. 

(3) A list of the owners and operators of the 

facility or supplier identified in paragraph (i)(1) of this 

section, provided that, if the list includes the operators 

of the facility or supplier and the owners with control of 

the facility or supplier, the failure to include any other 

owners shall not make the certificate of representation 

incomplete.

(4) The following certification statements by the 

designated representative and any alternate designated 

representative:

(i) “I certify that I was selected as the designated 

representative or alternate designated representative, as 

applicable, by an agreement binding on the owners and 

operators of the facility or supplier, as applicable.”
49

(ii) “I certify that I have all the necessary 

authority to carry out my duties and responsibilities under 

40 CFR part 98 on behalf of the owners and operators of the 

facility or supplier, as applicable, and that each such 

owner and operator shall be fully bound by my 

representations, actions, inactions, or submissions.”

(iii) “I certify that the owners and operators of the 

facility or supplier, as applicable, shall be bound by any 

order issued to me by the Administrator or a court 

regarding the facility or supplier.”

(iv) “If there are multiple owners and operators of 

the facility or supplier, as applicable, I certify that I 

have given a written notice of my selection as the 

‘designated representative’ or ‘alternate designated 

representative’, as applicable, and of the agreement by 

which I was selected to each owner and operator of the 

facility or supplier."

(5) The signature of the designated representative 

and any alternate designated representative and the dates 

signed.

(j) Documents of agreement. Unless otherwise 

required by the Administrator, documents of agreement 

referred to in the certificate of representation shall not 

be submitted to the Administrator. The Administrator shall 
50

not be under any obligation to review or evaluate the 

sufficiency of such documents, if submitted.

(k) Binding nature of the certificate of 

representation. Once a complete certificate of 

representation under this section for a facility or 

supplier has been received, the Administrator will rely on 

the certificate of representation unless and until a later 

signed, complete certificate of representation under this 

section for the facility or supplier is received by the 

Administrator.

(l) Objections concerning a designated 

representative.

(1) Except as provided in paragraph (g) of this 

section, no objection or other communication submitted to 

the Administrator concerning the authorization, or any 

representation, action, inaction, or submission, of the 

designated representative or alternate designated 

representative shall affect any representation, action, 

inaction, or submission of the designated representative or 

alternate designated representative, or the finality of any 

decision or order by the Administrator under this part.

(2) The Administrator will not adjudicate any private 

legal dispute concerning the authorization or any 

representation, action, inaction, or submission of any 
51

designated representative or alternate designated 

representative.

(m) Delegation by designated representative and 

alternate designated representative.

(1) A designated representative or an alternate 

designated representative may delegate his or her own 

authority, to one or more individuals, to submit an 

electronic submission to the Administrator provided for or 

required under this part, except for a submission under 

this paragraph.

(2) In order to delegate his or her own authority, to 

one or more individuals, to submit an electronic submission 

to the Administrator in accordance with paragraph (m) (1) 

of this section, the designated representative or alternate 

designated representative must submit electronically to the 

Administrator a notice of delegation, in a format 

prescribed by the Administrator, that includes the 

following elements:

(i) The name, organization name (company affiliationemployer) address, e-mail address (if any), telephone 

number, and facsimile transmission number (if any) of such 

designated representative or alternate designated 

representative.
52

(ii) The name, address, e-mail address, telephone 

number, and facsimile transmission number (if any) of each 

such individual (referred to as an “agent”).

(iii) For each such individual, a list of the type or 

types of electronic submissions under paragraph (m)(1) of 

this section for which authority is delegated to him or 

her.

(iv) For each type of electronic submission listed in 

accordance with clause (iii), the facility or supplier for 

which the electronic submission may be made.

(v) The following certification statements by such 

designated representative or alternate designated 

representative:

(A) “I agree that any electronic submission to the 

Administrator that is by an agent identified in this notice 

of delegation and of a type listed, and for a facility or 

supplier designated, for such agent in this notice of 

delegation and that is made when I am a designated 

representative or alternate designated representative, as 

applicable, and before this notice of delegation is 

superseded by another notice of delegation under 

§98.4(m)(3) shall be deemed to be an electronic submission 

certified, signed, and submitted by me.”
53

(B) “Until this notice of delegation is superseded by 

a later signed notice of delegation under §98.4(m)(3), I 

agree to maintain an e-mail account and to notify the 

Administrator immediately of any change in my e-mail 

address unless all delegation of authority by me under 

§98.4(m) is terminated.”

(v) The signature of such designated representative 

or alternate designated representative and the date signed. 

(3) A notice of delegation submitted in accordance 

with paragraph (m)(2) of this section shall be effective, 

with regard to the designated representative or alternate 

designated representative identified in such notice, upon 

receipt of such notice by the Administrator and until 

receipt by the Administrator of another such notice that 

was signed later by such designated representative or 

alternate designated representative, as applicable. The 

later signed notice of delegation may replace any 

previously identified agent, add a new agent, or eliminate 

entirely any delegation of authority.

(4) Any electronic submission covered by the 

certification in paragraph (m)(2)(iv)(A) of this section 

and made in accordance with a notice of delegation 

effective under paragraph (m)(3) of this section shall be 

deemed to be an electronic submission certified, signed, 
54

and submitted by the designated representative or alternate 

designated representative submitting such notice of 

delegation.

§98.5 How is the report submitted?

Each GHG report and certificate of representation for 

a facility or supplier must be submitted electronically in 

accordance with the requirements of §98.4 and in a format 

specified by the Administrator. 

§98.6 Definitions.

All terms used in this part shall have the same 

meaning given in the Clean Air Act and in this section. 

Accuracy of a measurement at a specified level (e.g., 

one percent of full scale or one percent of the value 

measured) means that the mean of repeat measurements made 

by a device or technique are within 95 percent of the range 

bounded by the true value plus or minus the specified 

level.

Acid Rain Program means the program established under 

title IV of the Clean Air Act, and implemented under parts 

72 through 78 of this chapter for the reduction of sulfur 

dioxide and nitrogen oxides emissions.

Administrator means the Administrator of the United 

States Environmental Protection Agency or the 

Administrator’s authorized representative.
55

AGA means the American Gas Association

Agricultural byproducts means those parts of arable 

crops that are not used for the primary purpose of 

producing food. Agricultural byproducts include, but are 

not limited to, oat, corn and wheat straws, bagasse, peanut 

shells, rice and coconut husks, soybean hulls, palm kernel 

cake, cottonseed and sunflower seed cake, and pomace.

Alkali bypass means a duct between the feed end of the 

kiln and the preheater tower through which a portion of the 

kiln exit gas stream is withdrawn and quickly cooled by air 

or water to avoid excessive buildup of alkali, chloride 

and/or sulfur on the raw feed. This may also be referred 

to as the “kiln exhaust gas bypass.”

Anaerobic digester means the system where wastes are 

collected and anaerobically digested in large containment 

vessels or covered lagoons. Anaerobic digesters stabilize 

waste by the microbial reduction of complex organic 

compounds to CO2 and CH4, which is captured and may be 

flared or used as fuel. Anaerobic digestion systems, 

include but are not limited to covered lagoon, complete 

mix, plug flow, and fixed film digesters.

Anaerobic lagoon means a type of liquid storage system 

component, either at manure management system or a 

wastewater treatment system, that is designed and operated 
56

to stabilize wastes using anaerobic microbial processes. 

Anaerobic lagoons may be designed for combined 

stabilization and storage with varying lengths of retention 

time (up to a year or greater), depending on the climate 

region, the volatile solids loading rate, and other 

operational factors.

Anode effect is a process upset condition of an 

aluminum electrolysis cell caused by too little alumina 

dissolved in the electrolyte. The anode effect begins when 

the voltage rises rapidly and exceeds a threshold voltage, 

typically 8 volts. 

Anode Effect Minutes Per Cell Day (24 hours) are the 

total minutes during which an electrolysis cell voltage is 

above the threshold voltage, typically 8 volts.

ANSI means the American National Standards Institute.

API means the American Petroleum Institute.

Argon-oxygen decarburization (AOD) vessel means any 

closed-bottom, refractory-lined converter vessel with 

submerged tuyeres through which gaseous mixtures containing 

argon and oxygen or nitrogen may be blown into molten steel 

for further refining to reduce the carbon content of the 

steel.

ASABE means the American Society of Agricultural and 

Biological Engineers.
57

ASME means the American Society of Mechanical 

Engineers.

ASTM means the American Society of Testing and 

Materials.

Asphalt means a dark brown-to-black cement-like 

material obtained by petroleum processing and containing 

bitumens as the predominant component. It includes crude 

asphalt as well as the following finished products: 

cements, fluxes, the asphalt content of emulsions 

(exclusive of water), and petroleum distillates blended 

with asphalt to make cutback asphalts. 

Aviation Gasoline means a complex mixture of volatile 

hydrocarbons, with or without additives, suitably blended 

to be used in aviation reciprocating engines. 

Specifications can be found in ASTM Specification D910–07a, 

Standard Specification for Aviation Gasolines (incorporated 

by reference, see §98.7).

B0 means the maximum CH4 producing capacity of a waste 

stream, kg CH4/kg COD.

Basic oxygen furnace means any refractory-lined vessel 

in which high-purity oxygen is blown under pressure through 

a bath of molten iron, scrap metal, and fluxes to produce 

steel. 

bbl means barrel.
58

Biodiesel means a mono-akyl ester derived from biomass 

and conforming to ASTM D6751-08, Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate 

Fuels.

Biogenic CO2 means carbon dioxide emissions generated 

as the result of biomass combustion from combustion units 

for which emission calculations are required by an 

applicable part 98 subpart. 

Biomass means non-fossilized and biodegradable organic 

material originating from plants, animals or microorganisms, including products, by-products, residues and 

waste from agriculture, forestry and related industries as 

well as the non-fossilized and biodegradable organic 

fractions of industrial and municipal wastes, including 

gases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material. 

Blast furnace means a furnace that is located at an 

integrated iron and steel plant and is used for the 

production of molten iron from iron ore pellets and other 

iron bearing materials.

Blendstocks are petroleum products used for blending 

or compounding into finished motor gasoline. These include 

RBOB (reformulated blendstock for oxygenate blending) and 
59

CBOB (conventional blendstock for oxygenate blending), but 

exclude oxygenates, butane, and pentanes plus.

Blendstocks -- Others are products used for blending 

or compounding into finished motor gasoline that are not 

defined elsewhere. Excludes Gasoline Treated as Blendstock 

(GTAB), Diesel Treated as Blendstock (DTAB), conventional 

blendstock for oxygenate blending (CBOB), reformulated 

blendstock for oxygenate blending (RBOB), oxygenates (e.g. 

fuel ethanol and methyl tertiary butyl ether), butane, and 

pentanes plus. 

Blowdown mean the act of emptying or depressuring a 

vessel. This may also refer to the discarded material such 

as blowdown water from a boiler or cooling tower.

British Thermal Unit or Btu means the quantity of heat 

required to raise the temperature of one pound of water by 

one degree Fahrenheit at about 39.2 degrees Fahrenheit.

Bulk, with respect to industrial GHG suppliers and CO2 

suppliers, means the transfer of a product inside 

containers, including but not limited to tanks, cylinders, 

drums, and pressure vessels.

Bulk natural gas liquid or NGL refers to mixtures of 

hydrocarbons that have been separated from natural gas as 

liquids through the process of absorption, condensation, 

adsorption, or other methods. Generally, such liquids 
60

consist of ethane, propane, butanes, and pentanes plus. 

Bulk NGL is sold to fractionators or to refineries and 

petrochemical plants where the fractionation takes place.

Butane, or n-Butane, is a paraffinic straight-chain 

hydrocarbon with molecular formula C4H10.

Butylene, or n-Butylene, is an olefinic straight-chain 

hydrocarbon with molecular formula C4H8.

By-product coke oven battery means a group of ovens 

connected by common walls, where coal undergoes destructive 

distillation under positive pressure to produce coke and 

coke oven gas from which by-products are recovered.

Calcination means the process of thermally treating 

minerals to decompose carbonates from ore.

Calculation methodology means a methodology prescribed 

under the section “Calculating GHG Emissions” in any 

subpart of part 98.

Carbon dioxide equivalent or CO2e means the number of 

metric tons of CO2 emissions with the same global warming 

potential as one metric ton of another greenhouse gas, and 

is calculated using Equation A-1 of this subpart.

Carbon dioxide production well means any hole drilled 

in the earth for the primary purpose of extracting carbon 

dioxide from a geologic formation or group of formations 

which contain deposits of carbon dioxide.
61

Carbon dioxide production well facility means one or 

more carbon dioxide production wells that are located on 

one or more contiguous or adjacent properties, which are 

under the control of the same entity. Carbon dioxide 

production wells located on different oil and gas leases, 

mineral fee tracts, lease tracts, subsurface or surface 

unit areas, surface fee tracts, surface lease tracts, or 

separate surface sites, whether or not connected by a road, 

waterway, power line, or pipeline, shall be considered part 

of the same CO2 production well facility if they otherwise 

meet the definition.

Carbon dioxide stream means carbon dioxide that has 

been captured from an emission source (e.g. a power plant 

or other industrial facility) or extracted from a carbon 

dioxide production well plus incidental associated 

substances either derived from the source materials and the 

capture process or extracted with the carbon dioxide.

Carbon share means the percent of total mass that 

carbon represents in any product..

Carbonate means compounds containing the radical CO3

-2. 

Upon calcination, the carbonate radical decomposes to 

evolve carbon dioxide (CO2). Common carbonates consumed in 

the mineral industry include calcium carbonate (CaCO3) or 
62

calcite; magnesium carbonate (MgCO3) or magnesite; and 

calcium-magnesium carbonate (CaMg(CO3)2) or dolomite.

Carbonate-based mineral means any of the following 

minerals used in the manufacture of glass: calcium 

carbonate (CaCO3), calcium magnesium carbonate (CaMg(CO3)2), 

and sodium carbonate (Na2CO3).

Carbonate-based mineral mass fraction means the 

following: for limestone, the mass fraction of CaCO3 in the 

limestone; for dolomite, the mass fraction of CaMg(CO3)2 in 

the dolomite; and for soda ash, the mass fraction of Na2CO3 

in the soda ash.

Carbonate-based raw material means any of the 

following materials used in the manufacture of glass: 

limestone, dolomite, and soda ash.

Catalytic cracking unit means a refinery process unit 

in which petroleum derivatives are continuously charged and 

hydrocarbon molecules in the presence of a catalyst are 

fractured into smaller molecules, or react with a contact 

material suspended in a fluidized bed to improve feedstock 

quality for additional processing and the catalyst or 

contact material is continuously regenerated by burning off 

coke and other deposits. Catalytic cracking units include 

both fluidized bed systems, which are referred to as fluid 

catalytic cracking units (FCCU), and moving bed systems, 
63

which are also referred to as thermal catalytic cracking 

units. The unit includes the riser, reactor, regenerator, 

air blowers, spent catalyst or contact material stripper, 

catalyst or contact material recovery equipment, and 

regenerator equipment for controlling air pollutant 

emissions and for heat recovery.

Deep bedding systems for cattle swine means a manure 

management system in which, as manure accumulates, bedding 

is continually added to absorb moisture over a production 

cycle and possibly for as long as 6 to 12 months. This 

manure management system also is known as a bedded pack 

manure management system and may be combined with a dry lot 

or pasture.

CBOB-Summer (conventional blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Conventional-Summer.

CBOB-Winter (conventional blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Conventional-Winter.

Certified standards means calibration gases certified 

by the manufacturer of the calibration gases to be accurate 
64

to within 2 percent of the value on the label or 

calibration gases.

CH4 means methane.

Chemical recovery combustion unit means a combustion 

device, such as a recovery furnace or fluidized-bed reactor 

where spent pulping liquor from sulfite or semi-chemical 

pulping processes is burned to recover pulping chemicals.

Chemical recovery furnace means an enclosed combustion 

device where concentrated spent liquor produced by the 

kraft or soda pulping process is burned to recover pulping 

chemicals and produce steam. Includes any recovery furnace 

that burns spent pulping liquor produced from both the 

kraft and soda pulping processes.

Chloride process means a production process where 

titanium dioxide is produced using calcined petroleum coke 

and chlorine as raw materials.

City gate means a location at which natural gas 

ownership or control passes from one party to another, 

neither of which is the ultimate consumer. In this rule, 

in keeping with common practice, the term refers to a point 

or measuring station at which a local gas distribution 

utility receives gas from a natural gas pipeline company or 

transmission system. Meters at the city gate station 

measure the flow of natural gas into the local distribution 
65

company system and typically are used to measure local 

distribution company system sendout to customers. 

CO2 means carbon dioxide.

Coal means all solid fuels classified as anthracite, 

bituminous, sub-bituminous, or lignite by the American 

Society for Testing and Materials Designation ASTM D388–05 

Standard Classification of Coals by Rank (incorporated by 

reference, see §98.7).

COD means the chemical oxygen demand as determined 

using methods specified pursuant to 40 CFR part 136.

Coke burn-off means the coke removed from the surface 

of a catalyst by combustion during catalyst regeneration. 

Coke burn-off also means the coke combusted in fluid coking 

unit burner.

Cokemaking means the production of coke from coal in 

either a by-product coke oven battery or a non-recovery 

coke oven battery.

Commercial Applications means executing a commercial 

transaction subject to a contract. A commercial application 

includes transferring custody of a product from one 

facility to another if it otherwise meets the definition. 

Company records means, in reference to the amount of 

fuel consumed by a stationary combustion unit (or by a 

group of such units), a complete record of the methods 
66

used, the measurements made, and the calculations performed 

to quantify fuel usage. Company records may include, but 

are not limited to, direct measurements of fuel consumption 

by gravimetric or volumetric means, tank drop measurements, 

and calculated values of fuel usage obtained by measuring 

auxiliary parameters such as steam generation or unit 

operating hours. Fuel billing records obtained from the 

fuel supplier qualify as company records. 

Connector means to flanged, screwed, or other joined 

fittings used to connect pipe line segments, tubing, pipe 

components (such as elbows, reducers, “T’s” or valves) or a 

pipe line and a piece of equipment or an instrument to a 

pipe, tube or piece of equipment. A common connector is a 

flange. Joined fittings welded completely around the 

circumference of the interface are not considered 

connectors for the purpose of this part.

Container glass means glass made of soda-lime recipe, 

clear or colored, which is pressed and/or blown into 

bottles, jars, ampoules, and other products listed in North 

American Industry Classification System 327213 (NAICS 

327213).

Continuous emission monitoring system or CEMS means 

the total equipment required to sample, analyze, measure, 

and provide, by means of readings recorded at least once 
67

every 15 minutes, a permanent record of gas concentrations, 

pollutant emission rates, or gas volumetric flow rates from 

stationary sources.

Continuous glass melting furnace means a glass melting 

furnace that operates continuously except during periods of 

maintenance, malfunction, control device installation, 

reconstruction, or rebuilding.

Conventional—Summer refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which do not meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40, but 

which meet summer RVP standards required under 40 CFR 80.27 

or as specified by the state. Note: This category excludes 

conventional gasoline for oxygenate blending (CBOB) as well 

as other blendstock.

Conventional—Winter refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which do not meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 or the 

summer RVP standards required under 40 CFR 80.27 or as 

specified by the state. Note: This category excludes 
68

conventional blendstock for oxygenate blending (CBOB) as 

well as other blendstock.

Crude oil means a mixture of hydrocarbons that exists 

in the liquid phase in the underground reservoir and 

remains liquid at atmospheric pressure after passing 

through surface separating facilities. 

Daily spread means a manure management system 

component in which manure is routinely removed from a 

confinement facility and is applied to cropland or pasture 

within 24 hours of excretion.

Day means any consistently designated 24 hour period 

during which an emission unit is operated.

Degradable organic carbon (DOC) means the fraction of 

the total mass of a waste material that can be biologically 

degraded.

Delayed coking unit means one or more refinery process 

units in which high molecular weight petroleum derivatives 

are thermally cracked and petroleum coke is produced in a 

series of closed, batch system reactors. A delayed coking 

unit consists of the coke drums and ancillary equipment 

associated with a single fractionator.

Density means the mass contained in a given unit 

volume (mass/volume).
69

Destruction means, with respect to landfills and 

manure management, the combustion of methane in any on-site 

or off-site combustion technology. Destroyed methane 

includes, but is not limited to, methane combusted by 

flaring, methane destroyed by thermal oxidation, methane 

combusted for use in on-site energy or heat production 

technologies, methane that is conveyed through pipelines 

(including natural gas pipelines) for off-site combustion, 

and methane that is collected for any other on-site or offsite use as a fuel.

Destruction means, with respect to fluorinated GHGs, 

the expiration of a fluorinated GHG to the destruction 

efficiency actually achieved. Such destruction does not 

result in a commercially useful end product. 

Destruction Efficiency means the efficiency with which 

a destruction device reduces the GWP-weighted mass of 

greenhouse gases fed into the device, considering the GWPweighted masses of both the greenhouse gases fed into the 

device and those exhausted from the device. The 

Destruction Efficiency is expressed in Equation A-2 of this 

section:

IN

OUT

tCO e

tCO e

DE

2

2

 1 (Eq. A-2)

Where:
70

DE = Destruction Efficiency 

tCO2eIN = The GWP-weighted mass of GHGs fed into the 

destruction device

tCO2eOUT = The GWP-weighted mass of GHGs exhausted from 

the destruction device, including GHGs 

formed during the destruction process 

Destruction efficiency, or flaring destruction 

efficiency, refers to the fraction of the gas that leaves 

the flare partially or fully oxidized.

Diesel–Other is any distillate fuel oil not defined 

elsewhere, including Diesel Treated as Blendstock (DTAB).

DIPE (diisopropyl ether, (CH3)2CHOCH(CH3)2) is an ether 

as described in "Oxygenates."

Direct liquefaction means the conversion of coal 

directly into liquids, rather than passing through an 

intermediate gaseous state.

Direct reduction furnace means a high temperature 

furnace typically fired with natural gas to produce solid 

iron from iron ore or iron ore pellets and coke, coal, or 

other carbonaceous materials.

Distillate Fuel Oil means a classification for one of 

the petroleum fractions produced in conventional 

distillation operations and from crackers and hydrotreating 

process units. The generic term distillate fuel oil 

includes kerosene, kerosene-type jet fuel, diesel fuels 
71

(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel 

Oils No. 1, No. 2, and No. 4). 

Distillate Fuel No. 1 has a maximum distillation 

temperature of 550 °F at the 90 percent recovery point and 

a minimum flash point of 100 °F and includes fuels commonly 

known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes 

kerosene. This fuel is further subdivided into categories 

of sulfur content: High Sulfur (greater than 500 ppm), Low 

Sulfur (less than or equal to 500 ppm and greater than 15 

ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 2 has a minimum and maximum 

distillation temperature of 540 °F and 640 °F at the 90 

percent recovery point, respectively, and includes fuels 

commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. 

This fuel is further subdivided into categories of sulfur 

content: High Sulfur (greater than 500 ppm), Low Sulfur 

(less than or equal to 500 ppm and greater than 15 ppm), 

and Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 4 is a distillate fuel oil made by 

blending distillate fuel oil and residual fuel oil, with a 

minimum flash point of 131 °F.

DOCf means the fraction of DOC that actually decomposes 

under the (presumably anaerobic) conditions within the 

landfill. 
72

Dry lot means a manure management system component 

consisting of a paved or unpaved open confinement area 

without any significant vegetative cover where accumulating 

manure may be removed periodically.

Electric arc furnace (EAF) means a furnace that 

produces molten alloy metal and heats the charge materials 

with electric arcs from carbon electrodes.

Electric arc furnace steelmaking means the production 

of carbon, alloy, or specialty steels using an EAF. This 

definition excludes EAFs at steel foundries and EAFs used 

to produce nonferrous metals.

Electrothermic furnace means a furnace that heats the 

charged materials with electric arcs from carbon 

electrodes.

Emergency generator means a stationary combustion 

device, such as a reciprocating internal combustion engine 

or turbine that serves solely as a secondary source of 

mechanical or electrical power whenever the primary energy 

supply is disrupted or discontinued during power outages or 

natural disasters that are beyond the control of the owner 

or operator of a facility. An emergency generator operates 

only during emergency situations, for training of personnel 

under simulated emergency conditions, as part of emergency 

demand response procedures, or for standard performance 
73

testing procedures as required by law or by the generator 

manufacturer. A generator that serves as a back-up power 

source under conditions of load shedding, peak shaving, 

power interruptions pursuant to an interruptible power 

service agreement, or scheduled facility maintenance shall 

not be considered an emergency generator. 

Emergency equipment means any auxiliary fossil fuelpowered equipment, such as a fire pump, that is used only 

in emergency situations.

ETBE (ethyl tertiary butyl ether, (CH3)3COC2H) is an 

ether as described in "Oxygenates."

Ethane is a paraffinic hydrocarbon with molecular 

formula C2H6. 

Ethanol is an anhydrous alcohol with molecular formula 

C2H5OH. 

Ethylene is an olefinic hydrocarbon with molecular 

formula C2H4. 

Ex refinery gate means the point at which a petroleum 

product leaves the refinery.

Experimental furnace means a glass melting furnace 

with the sole purpose of operating to evaluate glass 

melting processes, technologies, or glass products. An 

experimental furnace does not produce glass that is sold 

(except for further research and development purposes) or 
74

that is used as a raw material for non-experimental 

furnaces.

Export means to transport a product from inside the 

United States to persons outside the United States, 

excluding any such transport on behalf of the United States 

military including foreign military sales under the Arms 

Export Control Act.

Exporter means any person, company or organization of 

record that transfers for sale or for other benefit, 

domestic products from the United States to another country 

or to an affiliate in another country, excluding any such 

transfers on behalf of the United States military or 

military purposes including foreign military sales under 

the Arms Export Control Act. An exporter is not the entity 

merely transporting the domestic products, rather an 

exporter is the entity deriving the principal benefit from 

the transaction. 

Facility means any physical property, plant, building, 

structure, source, or stationary equipment located on one 

or more contiguous or adjacent properties in actual 

physical contact or separated solely by a public roadway or 

other public right-of-way and under common ownership or 

common control, that emits or may emit any greenhouse gas. 

Operators of military installations may classify such 
75

installations as more than a single facility based on 

distinct and independent functional groupings within 

contiguous military properties.

Feed means the prepared and mixed materials, which 

include but are not limited to materials such as limestone, 

clay, shale, sand, iron ore, mill scale, cement kiln dust 

and flyash, that are fed to the kiln. Feed does not 

include the fuels used in the kiln to produce heat to form 

the clinker product.

Feedstock means raw material inputs to a process that 

are transformed by reaction, oxidation, or other chemical 

or physical methods into products and by-products. 

Supplemental fuel burned to provide heat or thermal energy 

is not a feedstock.

Fischer-Tropsch process means a catalyzed chemical 

reaction in which synthesis gas, a mixture of carbon 

monoxide and hydrogen, is converted into liquid 

hydrocarbons of various forms.

Flare means a combustion device, whether at ground 

level or elevated, that uses an open flame to burn 

combustible gases with combustion air provided by 

uncontrolled ambient air around the flame. 
76

Flat glass means glass made of soda-lime recipe and 

produced into continuous flat sheets and other products 

listed in NAICS 327211.

Flowmeter means a device that measures the mass or 

volumetric rate of flow of a gas, liquid, or solid moving 

through an open or closed conduit (e.g. flowmeters include, 

but are not limited to, rotameters, turbine meters, 

coriolis meters, orifice meters, ultra-sonic flowmeters, 

and vortex flowmeters).

Fluid coking unit means one or more refinery process 

units in which high molecular weight petroleum derivatives 

are thermally cracked and petroleum coke is continuously 

produced in a fluidized bed system. The fluid coking unit 

includes equipment for controlling air pollutant emissions 

and for heat recovery on the fluid coking burner exhaust 

vent. There are two basic types of fluid coking units: a 

traditional fluid coking unit in which only a small portion 

of the coke produced in the unit is burned to fuel the unit 

and the fluid coking burner exhaust vent is directed to the 

atmosphere (after processing in a CO boiler or other air 

pollutant control equipment) and a flexicoking unit in 

which an auxiliary burner is used to partially combust a 

significant portion of the produced petroleum coke to 
77

generate a low value fuel gas that is used as fuel in other 

combustion sources at the refinery.

Fluorinated greenhouse gas means sulfur hexafluoride 

(SF6), nitrogen trifluoride (NF3), and any fluorocarbon 

except for controlled substances as defined at 40 CFR part 

82, subpart A and substances with vapor pressures of less 

than 1 mm of Hg absolute at 25 degrees C. With these 

exceptions, “fluorinated GHG” includes but is not limited 

to any hydrofluorocarbon, any perfluorocarbon, any fully 

fluorinated linear, branched or cyclic alkane, ether, 

tertiary amine or aminoether, any perfluoropolyether, and 

any hydrofluoropolyether. 

Fossil fuel means natural gas, petroleum, coal, or any 

form of solid, liquid, or gaseous fuel derived from such 

material, for purpose of creating useful heat.

Fractionators means plants that produce fractionated 

natural gas liquids (NGLs) extracted from produced natural 

gas and separate the NGLs individual component products: 

ethane, propane, butanes and pentane-plus (C5+). Plants 

that only process natural gas but do not fractionate NGLs 

further into component products are not considered 

fractionators. Some fractionators do not process 

production gas, but instead fractionate bulk NGLs received 

from natural gas processors. Some fractionators both 
78

process natural gas and fractionate bulk NGLs received from 

other plants.

Fuel means solid, liquid or gaseous combustible 

material.

Fuel gas means gas generated at a petroleum refinery, 

petrochemical plant, or similar industrial process unit, 

and that is combusted separately or in any combination with 

any type of gas.

Fuel gas system means a system of compressors, piping, 

knock-out pots, mix drums, and, if necessary, units used to 

remove sulfur contaminants from the fuel gas (e.g., amine 

scrubbers) that collects fuel gas from one or more sources 

for treatment, as necessary, and transport to a stationary 

combustion unit. A fuel gas system may have an 

overpressure vent to a flare but the primary purpose for a 

fuel gas system is to provide fuel to the various 

combustion units at the refinery or petrochemical plant.

Gas collection system or landfill gas collection 

system means a system of pipes used to collect landfill gas 

from different locations in the landfill to a single 

location for treatment (thermal destruction) or use. 

Landfill gas collection systems may also include knock-out 

or separator drums and/or a compressor. 
79

Gas-fired unit means a stationary combustion unit that 

derives more than 50 percent of its annual heat input from 

the combustion of gaseous fuels, and the remainder of its 

annual heat input from the combustion of fuel oil or other 

liquid fuels. 

Gas monitor means an instrument that continuously 

measures the concentration of a particular gaseous species 

in the effluent of a stationary source.

Gaseous fuel means a material that is in the gaseous 

state at standard atmospheric temperature and pressure 

conditions and that is combusted to produce heat and/or 

energy.

Gasification means the conversion of a solid or liquid 

raw material into a gas.

Gasoline – Other is any gasoline that is not defined 

elsewhere, including GTAB (gasoline treated as blendstock). 

Glass melting furnace means a unit comprising a 

refractory-lined vessel in which raw materials are charged 

and melted at high temperature to produce molten glass.

Glass produced means the weight of glass exiting a

glass melting furnace.

Global warming potential or GWP means the ratio of the 

time-integrated radiative forcing from the instantaneous 
80

release of one kilogram of a trace substance relative to 

that of one kilogram- of a reference gas, i.e., CO2. 

GPA means the Gas Processors Association.

Greenhouse gas or GHG means carbon dioxide (CO2), 

methane (CH4), nitrous oxide (N2O), sulfur hexafluoride 

(SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 

and other fluorinated greenhouse gases as defined in this

section.

GTBA (gasoline-grade tertiary butyl alcohol, 

(CH3)3COH), or t-butanol, is an alcohol as described in 

"Oxygenates."

Heavy Gas Oils are petroleum distillates with an 

approximate boiling range from 651 °F to 1,000 °F. 

Heel means the amount of gas that remains in a 

shipping container after it is discharged or off-loaded 

(that is no more than ten percent of the volume of the 

container).

High heat value or HHV means the high or gross heat 

content of the fuel with the heat of vaporization included. 

The water is assumed to be in a liquid state.

Hydrofluorocarbons or HFCs means a class of GHGs 

consisting of hydrogen, fluorine, and carbon.

Import means, to land on, bring into, or introduce 

into, any place subject to the jurisdiction of the United 
81

States whether or not such landing, bringing, or 

introduction constitutes an importation within the meaning 

of the customs laws of the United States, with the 

following exemptions:

(1) Off-loading used or excess fluorinated GHGs or 

nitrous oxide of U.S. origin from a ship during servicing.

(2) Bringing fluorinated GHGs or nitrous oxide into 

the U.S. from Mexico where the fluorinated GHGs or nitrous 

oxide had been admitted into Mexico in bond and were of 

U.S. origin. 

(3) Bringing fluorinated GHGs or nitrous oxide into 

the U.S. when transported in a consignment of personal or 

household effects or in a similar non-commercial situation 

normally exempted from U.S. Customs attention. 

(4) Bringing fluorinated GHGs or nitrous into U.S. 

jurisdiction exclusively for U. S. military purposes.

Importer means any person, company, or organization of 

record that for any reason brings a product into the United 

States from a foreign country, excluding introduction into 

U.S. jurisdiction exclusively for United States military 

purposes. An importer is the person, company, or 

organization primarily liable for the payment of any duties 

on the merchandise or an authorized agent acting on their 

behalf. The term includes, as appropriate:
82

(1) The consignee.

(2) The importer of record. 

(3) The actual owner.

(4) The transferee, if the right to draw merchandise 

in a bonded warehouse has been transferred. 

Indurating furnace means a furnace where unfired

taconite pellets, called green balls, are hardened at high 

temperatures to produce fired pellets for use in a blast 

furnace. Types of indurating furnaces include straight 

gate and grate kiln furnaces.

Industrial greenhouse gases means nitrous oxide or any 

fluorinated greenhouse gas.

In-line kiln/raw mill means a system in a portland 

cement production process where a dry kiln system is 

integrated with the raw mill so that all or a portion of 

the kiln exhaust gases are used to perform the drying 

operation of the raw mill, with no auxiliary heat source 

used. In this system the kiln is capable of operating 

without the raw mill operating, but the raw mill cannot 

operate without the kiln gases, and consequently, the raw 

mill does not generate a separate exhaust gas stream.

Isobutane is a paraffinic branch chain hydrocarbon 

with molecular formula C4H10.
83

Isobutylene is an olefinic branch chain hydrocarbon 

with molecular formula C4H8.

Kerosene is a light petroleum distillate with a 

maximum distillation temperature of 400 °F at the 10-

percent recovery point, a final maximum boiling point of 

572 °F, a minimum flash point of 100 °F, and a maximum 

freezing point of -22 °F. Included are No. 1-K and No. 2-K, 

distinguished by maximum sulfur content (0.04 and 0.30 

percent of total mass, respectively), as well as all other 

grades of kerosene called range or stove oil. Excluded is 

kerosene-type jet fuel (see definition herein).

Kerosene-Type Jet Fuel means a kerosene-based product 

used in commercial and military turbojet and turboprop 

aircraft. The product has a maximum distillation 

temperature of 400 °F at the 10 percent recovery point and 

a final maximum boiling point of 572 °F. Included are Jet 

A, Jet A-1, JP-5, and JP-8.

Kiln means an oven, furnace, or heated enclosure used

for thermally processing a mineral or mineral-based 

substance.

Landfill means an area of land or an excavation in 

which wastes are placed for permanent disposal and that is 

not a land application unit, surface impoundment, injection 
84

well, or waste pile as those terms are defined under 40 CFR 

257.2.

Landfill gas means gas produced as a result of 

anaerobic decomposition of waste materials in the landfill. 

Landfill gas generally contains 40 to 60 percent methane on 

a dry basis, typically less than 1 percent non-methane 

organic chemicals, and the remainder being carbon dioxide.

Lime is the generic term for a variety of chemical 

compounds that are produced by the calcination of limestone 

or dolomite. These products include but are not limited to 

calcium oxide, high-calcium quicklime, calcium hydroxide, 

hydrated lime, dolomitic quicklime, and dolomitic hydrate.

Liquid/Slurry means a manure management component in 

which manure is stored as excreted or with some minimal 

addition of water to facilitate handling and is stored in 

either tanks or earthen ponds, usually for periods less 

than one year.

Lubricants include all grades of lubricating oils, 

from spindle oil to cylinder oil to those used in greases. 

Petroleum lubricants may be produced from distillates or 

residues.

Makeup chemicals means carbonate chemicals (e.g., 

sodium and calcium carbonates) that are added to the 
85

chemical recovery areas of chemical pulp mills to replace 

chemicals lost in the process.

Manure composting means the biological oxidation of a 

solid waste including manure usually with bedding or 

another organic carbon source typically at thermophilic 

temperatures produced by microbial heat production. There 

are four types of composting employed for manure 

management: static, in vessel, intensive windrow and 

passive windrow. Static composting typically occurs in an 

enclosed channel, with forced aeration and continuous 

mixing. In vessel composting occurs in piles with forced 

aeration but no mixing. Intensive windrow composting occurs 

in windrows with regular turning for mixing and aeration. 

Passive windrow composting occurs in windrows with 

infrequent turning for mixing and aeration.

Maximum rated heat input capacity means the hourly 

heat input to a unit (in mmBtu/hr), when it combusts the 

maximum amount of fuel per hour that it is capable of 

combusting on a steady state basis, as of the initial 

installation of the unit, as specified by the manufacturer.

Maximum rated input capacity means the maximum 

charging rate of a municipal waste combustor unit expressed 

in tons per day of municipal solid waste combusted, 
86

calculated according to the procedures under 40 CFR 

60.58b(j).

Mcf means thousand cubic feet.

Methane conversion factor means the extent to which 

the CH4 producing capacity (Bo) is realized in each type of 

treatment and discharge pathway and system. Thus, it is an 

indication of the degree to which the system is anaerobic.

Methane correction factor means an adjustment factor 

applied to the methane generation rate to account for 

portions of the landfill that remain aerobic. The methane 

correction factor can be considered the fraction of the 

total landfill waste volume that is ultimately disposed of 

in an anaerobic state. Managed landfills that have soil or 

other cover materials have a methane correction factor of 

1. 

Methanol (CH3OH) is an alcohol as described in 

"Oxygenates."

Midgrade gasoline has an octane rating greater than or 

equal to 88 and less than or equal to 90. This definition 

applies to the midgrade categories of Conventional-Summer, 

Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For midgrade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition 

refers to the expected octane rating of the finished 
87

gasoline after oxygenate has been added to the RBOB or 

CBOB.

Miscellaneous Products include all refined petroleum 

products not defined elsewhere. It includes, but is not 

limited to, naphtha-type jet fuel (Jet B and JP-4), 

petrolatum lube refining by-products (aromatic extracts and 

tars), absorption oils, ram-jet fuel, petroleum rocket 

fuels, synthetic natural gas feedstocks, waste feedstocks, 

and specialty oils. It excludes organic waste sludges, tank 

bottoms, spent catalysts, and sulfuric acid.

MMBtu means million British thermal units.

Motor gasoline (finished) means a complex mixture of 

volatile hydrocarbons, with or without additives, suitably 

blended to be used in spark ignition engines. Motor 

gasoline includes conventional gasoline, reformulated 

gasoline, and all types of oxygenated gasoline. Gasoline 

also has seasonal variations in an effort to control ozone 

levels. This is achieved by lowering the Reid Vapor 

Pressure (RVP) of gasoline during the summer driving 

season. Depending on the region of the country the RVP is 

lowered to below 9.0 psi or 7.8 psi. The RVP may be further 

lowered by state regulations.

Mscf means million standard cubic feet.
88

MTBE (methyl tertiary butyl ether, (CH3)3COCH3) is an 

ether as described in "Oxygenates." 

Municipal solid waste landfill or MSW landfill means 

an entire disposal facility in a contiguous geographical 

space where household waste is placed in or on land. An 

MSW landfill may also receive other types of RCRA Subtitle 

D wastes (40 CFR 257.2) such as commercial solid waste, 

nonhazardous sludge, conditionally exempt small quantity 

generator waste, and industrial solid waste. Portions of 

an MSW landfill may be separated by access roads, public 

roadways, or other public right-of-ways. An MSW landfill 

may be publicly or privately owned.

Municipal solid waste or MSW means solid phase 

household, commercial/retail, and/or institutional waste. 

Household waste includes material discarded by single and 

multiple residential dwellings, hotels, motels, and other 

similar permanent or temporary housing establishments or 

facilities. Commercial/retail waste includes material 

discarded by stores, offices, restaurants, warehouses, nonmanufacturing activities at industrial facilities, and 

other similar establishments or facilities. Institutional 

waste includes material discarded by schools, nonmedical 

waste discarded by hospitals, material discarded by nonmanufacturing activities at prisons and government 
89

facilities, and material discarded by other similar 

establishments or facilities. Household, 

commercial/retail, and institutional waste does not include 

used oil, wood pellets, construction, renovation, and 

demolition wastes (which includes, but is not limited to, 

railroad ties and telephone poles), clean wood, industrial 

process or manufacturing wastes, medical waste, or motor 

vehicles (including motor vehicle parts or vehicle fluff). 

Household, commercial/retail, and institutional wastes 

include yard waste, refuse-derived fuel, and motor vehicle 

maintenance materials, limited to vehicle batteries and 

tires, except where a single waste stream consisting of 

tires is combusted in a unit. 

N2O means nitrous oxide.

Naphthas (< 401 °F) is a generic term applied to a 

petroleum fraction with an approximate boiling range 

between 122 °F and 400 °F. The naphtha fraction of crude 

oil is the raw material for gasoline and is composed 

largely of paraffinic hydrocarbons.

Natural gas means a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the earth’s surface, of which the 

principal constituent is methane. Natural gas may be field 

quality or pipeline quality. Natural gas is composed of at 
90

least 70 percent methane by volume or has a high heat value 

between 910 and 1150 Btu per standard cubic foot.

Natural gas liquids (NGLs) means those hydrocarbons in 

natural gas that are separated from the gas as liquids 

through the process of absorption, condensation, 

adsorption, or other methods. Generally, such liquids 

consist of ethane, propane, butanes, and pentanes plus. 

Bulk NGLs refers to mixtures of NGLs that are sold or 

delivered as undifferentiated product from natural gas 

processing plants.

Natural gasoline means a mixture of liquid

hydrocarbons (mostly pentanes and heavier hydrocarbons) 

extracted from natural gas. It includes isopentane. 

NIST means the United States National Institute of 

Standards and Technology.

Nitric acid production line means a series of reactors 

and absorbers used to produce nitric acid. 

Nitrogen excreted is the nitrogen that is excreted by 

livestock in manure and urine.

Non-crude feedstocks means any petroleum product or 

natural gas liquid that enters the refinery as a feedstock 

to be further refined or otherwise used on site.

Non-recovery coke oven battery means a group of ovens 

connected by common walls and operated as a unit, where 
91

coal undergoes destructive distillation under negative 

pressure to produce coke, and which is designed for the 

combustion of the coke oven gas from which by-products are 

not recovered.

Oil-fired unit means a stationary combustion unit that 

derives more than 50 percent of its annual heat input from 

the combustion of fuel oil, and the remainder of its annual 

heat input from the combustion of natural gas or other 

gaseous fuels. 

Open-ended valve or Lines (OELs) means any valve, 

except pressure relief valves, having one side of the valve 

seat in contact with process fluid and one side open to 

atmosphere, either directly or through open piping.

Operating hours means the duration of time in which a 

process or process unit is utilized; this excludes 

shutdown, maintenance, and standby.

Operational change means, for purposes of §98.3(b), a 

change in the type of feedstock or fuel used, a change in 

operating hours, or a change in process production rate.

Operator means any person who operates or supervises a 

facility or supplier.

Other Oils (> 401 °F) are oils with a boiling range 

equal to or greater than 401 °F that are generally intended
92

for use as a petrochemical feedstock and are not defined 

elsewhere.

Owner means any person who has legal or equitable 

title to, has a leasehold interest in, or control of a 

facility or supplier, except a person whose legal or 

equitable title to or leasehold interest in the facility or 

supplier arises solely because the person is a limited 

partner in a partnership that has legal or equitable title 

to, has a leasehold interest in, or control of the facility 

or supplier shall not be considered an “owner” of the 

facility or supplier. 

Oxygenates means substances which, when added to 

gasoline, increase the oxygen content of the gasoline. 

Common oxygenates are ethanol, methyl tertiary butyl ether 

(MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl 

methyl ether (TAME), diisopropyl ether (DIPE), and 

methanol. 

Pasture/Range/Paddock means the manure from pasture 

and range grazing animals is allowed to lie as deposited, 

and is not managed.

Pentanes Plus, or C5+, is a mixture of hydrocarbons 

that is a liquid at ambient temperature and pressure, and 

consists mostly of pentanes (five carbon chain) and higher 

carbon number hydrocarbons. Pentanes plus includes, but is 
93

not limited to, normal pentane, isopentane, hexanes-plus 

(natural gasoline), and plant condensate.

Perfluorocarbons or PFCs means a class of greenhouse 

gases consisting on the molecular level of carbon and 

fluorine.

Petrochemical means methanol, acrylonitrile, ethylene, 

ethylene oxide, ethylene dichloride, and any form of carbon 

black.

Petrochemical Feedstocks means feedstocks derived from 

petroleum for the manufacture of chemicals, synthetic 

rubber, and a variety of plastics. This category is 

usually divided into naphthas less than 401 °F and other 

oils greater than 401 °F.

Petroleum means oil removed from the earth and the oil 

derived from tar sands and shale.

Petroleum coke means a black solid residue, obtained 

mainly by cracking and carbonizing of petroleum derived 

feedstocks, vacuum bottoms, tar and pitches in processes 

such as delayed coking or fluid coking. It consists mainly 

of carbon (90 to 95 percent), has low ash content, and may 

be used as a feedstock in coke ovens. This product is also 

known as marketable coke or catalyst coke.

Petroleum product means all refined and semi-refined 

products that are produced at a refinery by processing 
94

crude oil and other petroleum-based feedstocks, including 

petroleum products derived from co-processing biomass and 

petroleum feedstock together, but not including plastics or 

plastic products. Petroleum products may be combusted for 

energy use, or they may be used either for non-energy 

processes or as non-energy products. The definition of 

petroleum product for importers and exporters excludes 

waxes.

Pit storage below animal confinement (deep pits) means 

the collection and storage of manure typically below a 

slatted floor in an enclosed animal confinement facility. 

This usually occurs with little or no added water for 

periods less than one year.

Portable means designed and capable of being carried 

or moved from one location to another. Indications of 

portability include but are not limited to wheels, skids, 

carrying handles, dolly, trailer, or platform. Equipment is 

not portable if any one of the following conditions exists: 

(1) The equipment is attached to a foundation. 

(2) The equipment or a replacement resides at the 

same location for more than 12 consecutive months. 

(3) The equipment is located at a seasonal facility 

and operates during the full annual operating period of the 

seasonal facility, remains at the facility for at least two 
95

years, and operates at that facility for at least three 

months each year. 

(4) The equipment is moved from one location to 

another in an attempt to circumvent the portable residence 

time requirements of this definition. 

Poultry manure with litter means a manure management 

system component that is similar to cattle and swine deep 

bedding except usually not combined with a dry lot or 

pasture. The system is typically used for poultry breeder 

flocks and for the production of meat type chickens 

(broiler) and other fowl.

Poultry manure without litter means a manure 

management system component that may manage manure in a 

liquid form, similar to open pits in enclosed animal 

confinement facilities. These systems may alternatively be 

designed and operated to dry manure as it accumulates. The 

latter is known as a high-rise manure management system and 

is a form of passive windrow manure composting when 

designed and operated properly.

Precision of a measurement at a specified level(e.g., 

one percent of full scale or one percent of the value 

measured) means that 95 percent of repeat measurements made 

by a device or technique are within the range bounded by 
96

the mean of the measurements plus or minus the specified 

level. 

Premium grade gasoline is gasoline having an antiknock 

index, i.e., octane rating, greater than 90. This 

definition applies to the premium grade categories of 

Conventional-Summer, Conventional-Winter, ReformulatedSummer, and Reformulated-Winter. For premium grade 

categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and 

CBOB-Winter, this definition refers to the expected octane 

rating of the finished gasoline after oxygenate has been 

added to the RBOB or CBOB.

Pressed and blown glass means glass which is pressed, 

blown, or both, into products such as light bulbs, glass 

fiber, technical glass, and other products listed in NAICS 

327212.

Pressure relief device or pressure relief valve or 

pressure safety valve means a safety device used to prevent 

operating pressures from exceeding the maximum allowable 

working pressure of the process equipment. A common 

pressure relief device is but not limited to a springloaded pressure relief valve. Devices that are actuated 

either by a pressure of less than or equal to 2.5 psig or 

by a vacuum are not pressure relief devices.
97

Primary fuel means the fuel that provides the greatest 

percentage of the annual heat input to a stationary fuel 

combustion unit.

Process emissions means the emissions from industrial 

processes (e.g., cement production, ammonia production) 

involving chemical or physical transformations other than 

fuel combustion. For example, the calcination of 

carbonates in a kiln during cement production or the 

oxidation of methane in an ammonia process results in the 

release of process CO2 emissions to the atmosphere. 

Emissions from fuel combustion to provide process heat are 

not part of process emissions, whether the combustion is 

internal or external to the process equipment.

Process unit means the equipment assembled and 

connected by pipes and ducts to process raw materials and 

to manufacture either a final product or an intermediate 

used in the onsite production of other products. The 

process unit also includes the purification of recovered 

byproducts. 

Process vent means means a gas stream that: (1) is 

discharged through a conveyance to the atmosphere either 

directly or after passing through a control device; (2) 

originates from a unit operation, including but not limited 

to reactors (including reformers, crackers, and furnaces, 
98

and separation equipment for products and recovered 

byproducts); and (3) contains or has the potential to 

contain GHG that is generated in the process. Process vent 

does not include safety device discharges, equipment leaks, 

gas streams routed to a fuel gas system or to a flare, 

discharges from storage tanks.

Propane is a paraffinic hydrocarbon with molecular 

formula C3H8. 

Propylene is an olefinic hydrocarbon with molecular 

formula C3H6.

Pulp mill lime kiln means the combustion units (e.g., 

rotary lime kiln or fluidized bed calciner) used at a kraft 

or soda pulp mill to calcine lime mud, which consists 

primarily of calcium carbonate, into quicklime, which is 

calcium oxide.

Pushing means the process of removing the coke from 

the coke oven at the end of the coking cycle. Pushing 

begins when coke first begins to fall from the oven into 

the quench car and ends when the quench car enters the 

quench tower.

Raw mill means a ball and tube mill, vertical roller 

mill or other size reduction equipment, that is not part of 

an in-line kiln/raw mill, used to grind feed to the 

appropriate size. Moisture may be added or removed from 
99

the feed during the grinding operation. If the raw mill is 

used to remove moisture from feed materials, it is also, by 

definition, a raw material dryer. The raw mill also 

includes the air separator associated with the raw mill.

RBOB-Summer (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Reformulated-Summer.

RBOB-Winter (reformulated blendstock for oxygenate 

blending) means a petroleum product which, when blended 

with a specified type and percentage of oxygenate, meets 

the definition of Reformulated-Winter.

Reformulated—Summer refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which meet the requirements of the 

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 and 40 

CFR 80.41, and summer RVP standards required under 40 CFR 

80.27 or as specified by the state. Reformulated gasoline 

excludes Reformulated Blendstock for Oxygenate Blending 

(RBOB) as well as other blendstock.

Reformulated—Winter refers to finished gasoline 

formulated for use in motor vehicles, the composition and 

properties of which meet the requirements of the 
100

reformulated gasoline regulations promulgated by the U.S. 

Environmental Protection Agency under 40 CFR 80.40 and 40 

CFR 80.41, but which do not meet summer RVP standards 

required under 40 CFR 80.27 or as specified by the state. 

Note: This category includes Oxygenated Fuels Program 

Reformulated Gasoline (OPRG). Reformulated gasoline 

excludes Reformulated Blendstock for Oxygenate Blending 

(RBOB) as well as other blendstock.

Regular grade gasoline is gasoline having an 

antiknock index, i.e., octane rating, greater than or equal 

to 85 and less than 88. This definition applies to the 

regular grade categories of Conventional-Summer, 

Conventional-Winter, Reformulated-Summer, and ReformulatedWinter. For regular grade categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOB-Winter, this definition 

refers to the expected octane rating of the finished 

gasoline after oxygenate has been added to the RBOB or 

CBOB.

Rendered animal fat, or tallow, means fats extracted 

from animals which are generally used as a feedstock in 

making biodiesel. 

Research and development means those activities 

conducted in process units or at laboratory bench-scale 

settings whose purpose is to conduct research and 
101

development for new processes, technologies, or products 

and whose purpose is not for the manufacture of products 

for commercial sale, except in a de minimis manner.

Residual Fuel Oil No. 5 (Navy Special) is a 

classification for the heavier fuel oil generally used in 

steam powered vessels in government service and inshore 

power plants. It has a minimum flash point of 131 °F.

Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a 

classification for the heavier fuel oil generally used for 

the production of electric power, space heating, vessel 

bunkering and various industrial purposes. It has a minimum 

flash point of 140 °F.

Residuum is residue from crude oil after distilling 

off all but the heaviest components, with a boiling range 

greater than 1,000 °F. 

Road Oil is any heavy petroleum oil, including 

residual asphaltic oil used as a dust palliative and 

surface treatment on roads and highways. It is generally 

produced in six grades, from 0, the most liquid, to 5, the 

most viscous.

Rotary lime kiln means a unit with an inclined 

rotating drum that is used to produce a lime product from 

limestone by calcination.
102

Safety device means a closure device such as a 

pressure relief valve, frangible disc, fusible plug, or any 

other type of device which functions exclusively to prevent 

physical damage or permanent deformation to a unit or its 

air emission control equipment by venting gases or vapors 

directly to the atmosphere during unsafe conditions 

resulting from an unplanned, accidental, or emergency 

event. A safety device is not used for routine venting of 

gases or vapors from the vapor headspace underneath a cover 

such as during filling of the unit or to adjust the 

pressure in response to normal daily diurnal ambient 

temperature fluctuations. A safety device is designed to 

remain in a closed position during normal operations and 

open only when the internal pressure, or another relevant 

parameter, exceeds the device threshold setting applicable 

to the air emission control equipment as determined by the 

owner or operator based on manufacturer recommendations, 

applicable regulations, fire protection and prevention 

codes and practices, or other requirements for the safe 

handling of flammable, combustible, explosive, reactive, or 

hazardous materials.

Semi-refined petroleum product means all oils 

requiring further processing. Included in this category 

are unfinished oils which are produced by the partial 
103

refining of crude oil and include the following: naphthas 

and lighter oils; kerosene and light gas oils; heavy gas 

oils; and residuum, and all products that require further 

processing or the addition of blendstocks.

Sendout means, in the context of a local distribution 

company, the total deliveries of natural gas to customers 

over a specified time interval (typically hour, day, month, 

or year). Sendout is the sum of gas received through the 

city gate, gas withdrawn from on-system storage or peak 

shaving plants, and gas produced and delivered into the 

distribution system; and is net of any natural gas injected 

into on-system storage. It comprises gas sales, exchange, 

deliveries, gas used by company, and unaccounted for gas. 

Sendout is measured at the city gate station, and other onsystem receipt points from storage, peak shaving, and 

production. 

Sensor means a device that measures a physical 

quantity/quality or the change in a physical 

quantity/quality, such as temperature, pressure, flow rate, 

pH, or liquid level.

SF6 means sulfur hexafluoride.

Shutdown means the cessation of operation of an 

emission source for any purpose.
104

Silicon carbide means an artificial abrasive produced 

from silica sand or quartz and petroleum coke.

Sinter process means a process that produces a fused 

aggregate of fine iron-bearing materials suited for use in 

a blast furnace. The sinter machine is composed of a 

continuous traveling grate that conveys a bed of ore fines 

and other finely divided iron-bearing material and fuel 

(typically coke breeze), a burner at the feed end of the 

grate for ignition, and a series of downdraft windboxes 

along the length of the strand to support downdraft 

combustion and heat sufficient to produce a fused sinter 

product.

Site means any combination of one or more graded pad 

sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is 

physically located.

Smelting furnace means a furnace in which lead-bearing 

materials, carbon-containing reducing agents, and fluxes 

are melted together to form a molten mass of material 

containing lead and slag.

Solid byproducts means plant matter such as vegetable 

waste, animal materials/wastes, and other solid biomass, 

except for wood, wood waste, and sulphite lyes (black 

liquor).
105

Solid storage is the storage of manure, typically for 

a period of several months, in unconfined piles or stacks. 

Manure is able to be stacked due to the presence of a 

sufficient amount of bedding material or loss of moisture 

by evaporation.

Sour gas means any gas that contains significant 

concentrations of hydrogen sulfide. Sour gas may include 

untreated fuel gas, amine stripper off-gas, or sour water 

stripper gas. 

Special naphthas means all finished products with the 

naphtha boiling range (290° to 470 °F) that are generally 

used as paint thinners, cleaners or solvents. These 

products are refined to a specified flash point. Special 

naphthas include all commercial hexane and cleaning 

solvents conforming to ASTM Specification D1836-07, 

Standard Specification for Commercial Hexanes, and D235-02 

(Reapproved 2007), Standard Specification for Mineral 

Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning 

Solvent), respectively. Naphthas to be blended or marketed 

as motor gasoline or aviation gasoline, or that are to be 

used as petrochemical and synthetic natural gas (SNG) 

feedstocks are excluded.
106

Spent liquor solids means the dry weight of the solids 

in the spent pulping liquor that enters the chemical 

recovery furnace or chemical recovery combustion unit.

Spent pulping liquor means the residual liquid 

collected from on-site pulping operations at chemical pulp 

facilities that is subsequently fired in chemical recovery 

furnaces at kraft and soda pulp facilities or chemical 

recovery combustion units at sulfite or semi-chemical pulp 

facilities.

Standard conditions or standard temperature and 

pressure (STP) means 68 degrees Fahrenheit and 14.7 pounds 

per square inch absolute.

Steam reforming means a catalytic process that 

involves a reaction between natural gas or other light 

hydrocarbons and steam. The result is a mixture of 

hydrogen, carbon monoxide, carbon dioxide, and water.

Still gas means any form or mixture of gases produced 

in refineries by distillation, cracking, reforming, and 

other processes. The principal constituents are methane, 

ethane, ethylene, normal butane, butylene, propane, and 

propylene.

Storage tank means a vessel (excluding sumps) that is 

designed to contain an accumulation of crude oil, 

condensate, intermediate hydrocarbon liquids, or produced 
107

water and that is constructed entirely of non-earthen 

materials (e.g., wood, concrete, steel, plastic) that 

provide structural support.

Sulfur recovery plant means all process units which 

recover sulfur or produce sulfuric acid from hydrogen 

sulfide (H2S) and/or sulfur dioxide (SO2) from a common 

source of sour gas at a petroleum refinery. The sulfur 

recovery plant also includes sulfur pits used to store the 

recovered sulfur product, but it does not include secondary 

sulfur storage vessels or loading facilities downstream of 

the sulfur pits. For example, a Claus sulfur recovery 

plant includes: reactor furnace and waste heat boiler, 

catalytic reactors, sulfur pits, and, if present, oxidation 

or reduction control systems, or incinerator, thermal 

oxidizer, or similar combustion device. Multiple sulfur 

recovery units are a single sulfur recovery plant only when 

the units share the same source of sour gas. Sulfur 

recovery units that receive source gas from completely 

segregated sour gas treatment systems are separate sulfur 

recovery plants.

Supplemental fuel means a fuel burned within a

petrochemical process that is not produced within the 

process itself.
108

Supplier means a producer, importer, or exporter of a 

fossil fuel or an industrial greenhouse gas.

Taconite iron ore processing means an industrial 

process that separates and concentrates iron ore from 

taconite, a low grade iron ore, and heats the taconite in 

an indurating furnace to produce taconite pellets that are 

used as the primary feed material for the production of 

iron in blast furnaces at integrated iron and steel plants.

TAME means tertiary amyl methyl ether, 

(CH3)2(C2H5)COCH3).

Trace concentrations means concentrations of less than 

0.1 percent by mass of the process stream.

Transform means to use and entirely consume (except 

for trace concentrations) nitrous oxide or fluorinated GHGs 

in the manufacturing of other chemicals for commercial 

purposes. Transformation does not include burning of 

nitrous oxide.

Transshipment means the continuous shipment of nitrous 

oxide or a fluorinated GHG from a foreign state of origin 

through the United States or its territories to a second 

foreign state of final destination, as long as the shipment 

does not enter into United States jurisdiction. A 

transshipment, as it moves through the United States or its 
109

territories, cannot be re-packaged, sorted or otherwise 

changed in condition.

Trona means the raw material (mineral) used to 

manufacture soda ash; hydrated sodium bicarbonate carbonate 

(e.g.Na2CO3.NaHCO3.2H2O).

Ultimate analysis means the determination of the 

percentages of carbon, hydrogen, nitrogen, sulfur, and 

chlorine and (by difference) oxygen in the gaseous products 

and ash after the complete combustion of a sample of an 

organic material.

Unfinished oils are all oils requiring further 

processing, except those requiring only mechanical 

blending.

United States means the 50 states, the District of 

Columbia, and U.S. possessions and territories.

Unstabilized crude oil means, for the purposes of this 

part, crude oil that is pumped from the well to a pipeline 

or pressurized storage vessel for transport to the refinery 

without intermediate storage in a storage tank at 

atmospheric pressures. Unstabilized crude oil is 

characterized by having a true vapor pressure of 5 pounds 

per square inch absolute (psia) or greater.

Valve means any device for halting or regulating the 

flow of a liquid or gas through a passage, pipeline, inlet, 
110

outlet, or orifice; including, but not limited to, gate, 

globe, plug, ball, butterfly and needle valves.

Vegetable Oil means oils extracted from vegetation 

that are generally used as a feedstock in making biodiesel.

Volatile solids are the organic material in livestock 

manure and consist of both biodegradable and nonbiodegradable fractions.

Waelz kiln means an inclined rotary kiln in which 

zinc–containing materials are charged together with a 

carbon reducing agent (e.g., petroleum coke, metallurgical 

coke, or anthracite coal).

Waste oil means a petroleum-derived or syntheticallyderived oil whose physical properties have changed as a 

result of storage, handling or use, such that the oil 

cannot be used for its original purpose. Waste oil 

consists primarily of automotive oils (e.g., used motor 

oil, transmission oil, hydraulic fluids, brake fluid, etc.) 

and industrial oils (e.g., industrial engine oils, 

metalworking oils, process oils, industrial grease, etc).

Waxes means a solid or semi-solid material at 77 °F 

consisting of a mixture of hydrocarbons obtained or derived 

from petroleum fractions, or through a Fischer-Tropsch type 

process, in which the straight chained paraffin series 

predominates. This includes all marketable wax, whether 
111

crude or refined, with a congealing point between 80 (or 

85) and 240 °F and a maximum oil content of 50 weight 

percent.

Wood residuals means wood waste recovered from three 

principal sources: municipal solid waste (MSW); 

construction and demolition debris; and primary timber 

processing. Wood residuals recovered from MSW include 

wooden furniture, cabinets, pallets and containers, scrap 

lumber (from sources other than construction and demolition 

activities), and urban tree and landscape residues. Wood 

residuals from construction and demolition debris originate 

from the construction, repair, remodeling and demolition of 

houses and non-residential structures. Wood residuals from 

primary timber processing include bark, sawmill slabs and 

edgings, sawdust, and peeler log cores. Other sources of 

wood residuals include, but are not limited to, railroad 

ties, telephone and utility poles, pier and dock timbers, 

wastewater process sludge from paper mills, and logging 

residues.

Wool fiberglass means fibrous glass of random texture, 

including fiberglass insulation, and other products listed 

in NAICS 327993.

You means an owner or operator subject to Part 98.
112

Zinc smelters means a facility engaged in the 

production of zinc metal, zinc oxide, or zinc alloy 

products from zinc sulfide ore concentrates, zinc calcine, 

or zinc-bearing scrap and recycled materials through the 

use of pyrometallurgical techniques involving the reduction 

and volatization of zinc-bearing feed materials charged to 

a furnace.

§98.7 What standardized methods are incorporated by 

reference into this part?

The materials listed in this section are incorporated 

by reference in the corresponding sections noted. These 

incorporations by reference were approved by the Director 

of Federal Register in accordance with 5 U.S.C. 552(a) and 

1 CFR part 51. These materials are incorporated as they 

exist on the date of approval, and a notice of any change 

in the materials will be published in the Federal Register. 

The materials are available for purchase at the 

corresponding address in this section. The materials are 

available for inspection at the EPA Docket Center, Public 

Reading Room, EPA West Building, Room 3334, 1301 

Constitution Avenue, NW, Washington, DC, phone (202) 566-

1744 and at the National Archives and Records 

Administration (NARA). For information on the availability 

of this material at NARA, call 202-741-6030, or go to: 
113

http://www.archives.gov/federal_register/code_of_federal_re

gulations/ibr_locations.html. 

(a) The following material is available for purchase 

from the Association of Fertilizer and Phosphate Chemists 

(AFPC), P. O. Box 1645, Bartow, Florida 33831, 

http://afpc.net.

(1) Phosphate Mining States Methods Used and Adopted 

by the Association of Fertilizer and Phosphate Chemists 

AFPC Manual 10th Edition 2009 - Version 1.9, incorporation 

by reference (IBR) approved for §98.264(a) and §98.264(b).

(b) [Reserved]

(c) The following material is available for purchase 

from the ASM International, 9639 Kinsman Road, Materials 

Park, OH 44073, (440) 338-5151, 

http://www.asminternational.org.

(1) ASM CS-104 UNS No. G10460 - Alloy Digest April 

1985 (Carbon Steel of Medium Carbon Content), incorporation 

by reference (IBR) approved for §98.174(b).

(2) [Reserved]

(d) The following material is available for purchase 

from the American Society of Mechanical Engineers (ASME), 

Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 

http://www.asme.org.
114

(1) ASME MFC-3M–2004 Measurement of Fluid Flow in 

Pipes Using Orifice, Nozzle, and Venturi, incorporation by 

reference (IBR) approved for §98.344(c) and §98.364(e).

(2) ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of 

Gas Flow by Turbine Meters, IBR approved for §98.344(c), 

and §98.364(e).

(3) [Reserved]

(4) ASME MFC-6M–1998 Measurement of Fluid Flow in 

Pipes Using Vortex Flowmeters, IBR approved for §98.344(c)

and §98.364(e).

(5) ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of 

Gas Flow by Means of Critical Flow Venturi Nozzles, IBR 

approved for §98.344(c) and §98.364(e).

(6) [Reserved]

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by 

Means of Coriolis Mass Flowmeters, IBR approved for 

§98.344(c).

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using 

Small Bore Precision Orifice Meters, IBR approved for 

§98.344(c) and §98.364(e).

(9) [Reserved]

(10) ASME MFC-18M-2001 Measurement of Fluid Flow 

Using Variable Area Meters, IBR approved for §98.344(c), 

and §98.364(e).
115

(11) [Reserved]

(e) The following material is available for purchase 

from the American Society for Testing and Material (ASTM), 

100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428-B2959, (800) 262-1373, 

http://www.astm.org.

(1) ASTM C25-06 Standard Test Method for Chemical 

Analysis of Limestone, Quicklime, and Hydrated Lime, 

incorporation by reference (IBR) approved for §98.114(b), 

§98.174(b), §98.184(b), §98.194(c), and §98.334(b).

(2) ASTM C114-09 Standard Test Methods for Chemical 

Analysis of Hydraulic Cement, IBR approved for §98.84(a), 

§98.84(b), and §98.84(c).

(3) ASTM D235-02 (Reapproved 2007) Standard 

Specification for Mineral Spirits (Petroleum Spirits) 

(Hydrocarbon Dry Cleaning Solvent), IBR approved for §98.6.

(4) ASTM D240-02 (Reapproved 2007) Standard Test 

Method for Heat of Combustion of Liquid Hydrocarbon Fuels 

by Bomb Calorimeter, IBR approved for §98.254(e).

(5) ASTM D388-05 Standard Classification of Coals by 

Rank, IBR approved for §98.6.

(6) ASTM D910-07a Standard Specification for Aviation 

Gasolines, IBR approved for §98.6.

(7) [Reserved]
116

(8) ASTM D1826-94 (Reapproved 2003) Standard Test 

Method for Calorific (Heating) Value of Gases in Natural 

Gas Range by Continuous Recording Calorimeter, IBR approved 

for §98.254(e).

(9) ASTM D1836-07 Standard Specification for 

Commercial Hexanes, IBR approved for §98.6.

(10) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography, IBR approved for 

§98.74(c), §98.164(b), §98.244(b), §98.254(d), and 

§98.344(b).

(11) ASTM D1946-90 (Reapproved 2006) Standard 

Practice for Analysis of Reformed Gas by Gas 

Chromatography, IBR approved for §98.74(c), §98.164(b), 

§98.254(d), §98.344(b), and §98.364(c).

(12) ASTM D2013-07 Standard Practice for Preparing 

Coal Samples for Analysis, IBR approved for §98.164(b).

(13) ASTM D2234/D2234M-07 Standard Practice for 

Collection of a Gross Sample of Coal, IBR approved for 

§98.164(b).

(14) ASTM D2502-04 Standard Test Method for 

Estimation of Mean Relative Molecular Mass of Petroleum 

Oils From Viscosity Measurements, IBR approved for 

§98.74(c).
117

(15) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure, IBR approved for §98.74(c).

(16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test 

Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide 

in High-Purity Ethylene by Gas Chromatography, IBR approved 

for §98.244(b).

(17) ASTM D2597-94 (Reapproved 2004) Standard Test 

Method for Analysis of Demethanized Hydrocarbon Liquid 

Mixtures Containing Nitrogen and Carbon Dioxide by Gas 

Chromatography, IBR approved for §98.164(b).

(18) ASTM D3176-89 (Reapproved 2002) Standard 

Practice for Ultimate Analysis of Coal and Coke, IBR 

approved for §98.74(c), §98.164(b), §98.244(b), §98.254(i), 

§98.284(c), §98.284(d), §98.314(c), §98.314(d), and 

§98.314(f).

(19) ASTM D3238-95 (Reapproved 2005) Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M 

Method, IBR approved for §98.74(c) and §98.164(b).

(20) ASTM D3588-98 (Reapproved 2003) Standard 

Practice for Calculating Heat Value, Compressibility 
118

Factor, and Relative Density of Gaseous Fuels, IBR approved 

for §98.254(e).

(21) ASTM D3682-01 (Reapproved 2006) Standard Test 

Method for Major and Minor Elements in Combustion Residues 

from Coal Utilization Processes, IBR approved for 

§98.144(b).

(22) ASTM D4057-06 Standard Practice for Manual 

Sampling of Petroleum and Petroleum Products, IBR approved 

for §98.164(b).

(23) ASTM D4177-95 (Reapproved 2005) Standard 

Practice for Automatic Sampling of Petroleum and Petroleum 

Products, IBR approved for §98.164(b).

(24) ASTM D4809-06 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method), IBR approved for §98.254(e).

(25) ASTM D4891-89 (Reapproved 2006) Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion, IBR approved for §98.254(e).

(26) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants, IBR 

approved for §98.74(c), §98.164(b), §98.244(b), and 

§98.254(i).
119

(27) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal, IBR approved for

§98.74(c), §98.114(b), §98.164(b), §98.174(b), §98.184(b), 

§98.244(b), §98.254(i), §98.274(b), §98.284(c), §98.284(d), 

§98.314(c), §98.314(d), §98.314(f), and §98.334(b).

(28) [Reserved]

(29) ASTM D6060-96 (Reapproved 2001) Standard 

Practice for Sampling of Process Vents With a Portable Gas 

Chromatograph, IBR approved for §98.244(b).

(30) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Interface Fourier Transform Infrared (FTIR) Spectroscopy, 

IBR approved for §98.54(b),§98.224(b), and §98.414(n).

(31) ASTM D6609-08 Standard Guide for Part-Stream 

Sampling of Coal, IBR approved for §98.164(b).

(32) ASTM D6751-08 Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate 

Fuels, IBR approved for §98.6.

(33) ASTM D6866-08 Standard Test Methods for 

Determining the Biobased Content of Solid, Liquid, and 

Gaseous Samples Using Radiocarbon Analysis, IBR approved 

for §98.34(d), §98.34(e), and §98.36(e).
120

(34) ASTM D6883-04 Standard Practice for Manual 

Sampling of Stationary Coal from Railroad Cars, Barges, 

Trucks, or Stockpiles, IBR approved for §98.164(b). 

(35) ASTM D7430-08ae1 Standard Practice for 

Mechanical Sampling of Coal, IBR approved for §98.164(b).

(36) ASTM D7459-08 Standard Practice for Collection 

of Integrated Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon Dioxide Emitted from 

Stationary Emissions Sources, IBR approved for §98.34(d), 

§98.34(e), and §98.36(e).

(37) ASTM E359-00 (Reapproved 2005)e1 Standard Test 

Methods for Analysis of Soda Ash (Sodium Carbonate), IBR 

approved for §98.294(a) and §98.294(b).

(38) ASTM E1019-08 Standard Test Methods for 

Determination of Carbon, Sulfur, Nitrogen, and Oxygen in 

Steel, Iron, Nickel, and Cobalt Alloys by Various 

Combustion and Fusion Techniques, IBR approved for 

§98.174(b).

(39) ASTM E1747-95 (Reapproved 2005) Standard Guide 

for Purity of Carbon Dioxide Used in Supercritical Fluid 

Applications, IBR approved for 98.424(b).

(40) ASTM E1915-07a Standard Test Methods for 

Analysis of Metal Bearing Ores and Related Materials by 
121

Combustion Infrared-Absorption Spectrometry, IBR approved 

for §98.174(b).

(41) ASTM E1941-04 Standard Test Method for 

Determination of Carbon in Refractory and Reactive Metals 

and Their Alloys, IBR approved for §98.114(b), §98.184(b), 

§98.334(b).

(42) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography, IBR approved for §98.164(b), §98.244(b), 

and §98.254(d), and §98.344(b).

(43) ASTM D2503-92(2007) Standard Test Method for 

Relative Molecular Mass (Molecular Weight) of Hydrocarbons 

by Thermoelectric Measurement of Vapor Pressure, IBR 

approved for §98.254(d).

(44) ASTM D2593-93(2009) Standard Test Method for 

Butadiene Purity and Hydrocarbon Impurities by Gas 

Chromatography, IBR approved for §98.244(b).

(f) The following material is available for purchase 

from the Gas Processors Association (GPA), 6526 East 60th 

Street, Tulsa, Oklahoma 74143, (918) 493-3872, 

http://www.gasprocessors.com.

(1) [Reserved]

(2) GPA 2261-00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography, IBR approved for 

§98.164(b), §98.254(d), and §98.344(b).
122

(g) The following material is available for purchase 

from the International Standards Organization (ISO), 1, ch. 

de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, 

Switzerland, +41 22 749 01 11, 

http://www.iso.org/iso/home.htm.

(1) ISO 3170: Petroleum liquids—Manual sampling -

Third Edition 2004-02-01, IBR approved for §98.164(b).

(2) ISO 3171: Petroleum Liquids—Automatic pipeline 

sampling - Second Edition 1988-12-01, IBR approved for 

§98.164(b).

(3) [Reserved]

(4) ISO/TR 15349-1: 1998, Unalloyed steel—

Determination of low carbon content. Part 1: Infrared 

absorption method after combustion in an electric 

resistance furnace (by peak separation) (1998-10-15) -

First Edition, IBR approved for §98.174(b).

(5) ISO/TR 15349-3: 1998, Unalloyed steel—

Determination of low carbon content. Part 3: Infrared 

absorption method after combustion in an electric 

resistance furnace (with preheating) (1998-10-15) - First 

Edition, IBR approved for §98.174(b).

(h) The following material is available for purchase 

from the National Lime Association (NLA), 200 North Glebe 
123

Road, Suite 800, Arlington, Virginia 22203, (703) 243-5463, 

http://www.lime.org.

(1) CO2 Emissions Calculation Protocol for the Lime 

Industry—English Units Version, February 5, 2008 Revision—

National Lime Association, incorporation by reference (IBR) 

approved for §98.194(c) and §98.194(e).

(i) The following material is available for purchase 

from the National Institute of Standards and Technology 

(NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 

20899-1070, (800) 877-8339, http://www.nist.gov/index.html.

(1) Specifications, Tolerances, and Other Technical 

Requirements For Weighing and Measuring Devices, NIST 

Handbook 44 (2009), incorporation by reference (IBR) 

approved for §98.244(b), §98.254(h), and §98.344(a).

(j) The following material is available for purchase 

from the Technical Association of the Pulp and Paper 

Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 

30092, (800) 332-8686, http://www.tappi.org. 

(1) T650 om-05 Solids Content of Black Liquor, TAPPI, 

incorporation by reference (IBR) approved for §98.276(c) 

and §98.277(d).

(2) T684 om-06 Gross Heating Value of Black Liquor, 

TAPPI, incorporation by reference (IBR) approved for 

§98.274(b).
124

(k) The following material is available from the U.S. 

Environmental Protection Agency, 1200 Pennsylvania Avenue, 

NW, Washington, D.C. 20460, (202) 272-0167, www.epa.gov. 

(1) Protocol for Measuring Destruction or Removal 

Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics Manufacturing, Version 1, EPA-430-

R-10-003.

§98.8 What are the compliance and enforcement provisions 

of this part? 

Any violation of any requirement of this part shall be 

a violation of the Clean Air Act, including section 114 (42 

U.S.C. §7414). A violation includes but is not limited to 

failure to report GHG emissions, failure to collect data 

needed to calculate GHG emissions, failure to continuously 

monitor and test as required, failure to retain records 

needed to verify the amount of GHG emissions, and failure 

to calculate GHG emissions following the methodologies 

specified in this part. Each day of a violation 

constitutes a separate violation.

§98.9 Addresses.

All requests, notifications, and communications to the 

Administrator pursuant to this part, other than submittal 

of the annual GHG report, shall be submitted to the 

following address:
125

(a) For U.S. mail.

Director, Climate Change Division

1200 Pennsylvania Ave., NW

Mail Code: 6207J

Washington, DC 20460

(b) For package deliveries.

Director, Climate Change Division

1310 L St, NW

Washington, DC 20005

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon)

Name CAS # Chemical formula

Global 

warming 

potential 

(100 yr.)

Carbon dioxide 124-38-9 CO2 1

Methane 74-82-8 CH4 21

Nitrous oxide 10024-97-2 N2O 310

HFC-23 75-46-7 CHF3 11,700

HFC-32 75-10-5 CH2F2 650

HFC-41 593-53-3 CH3F 150

HFC-125 354-33-6 C2HF5 2,800

HFC-134 359-35-3 C2H2F4 1,000

HFC-134a 811-97-2 CH2FCF3 1,300

HFC-143 430-66-0 C2H3F3 300

HFC-143a 420-46-2 C2H3F3 3,800

HFC-152 624-72-6 CH2FCH2F 53

HFC-152a 75-37-6 CH3CHF2 140

HFC-161 353-36-6 CH3CH2F 12

HFC-227ea 431-89-0 C3HF7 2,900

HFC-236cb 677-56-5 CH2FCF2CF3 1,340

HFC-236ea 431-63-0 CHF2CHFCF3 1,370

HFC-236fa 690-39-1 C3H2F6 6,300

HFC-245ca 679-86-7 C3H3F5 560

HFC-245fa 460-73-1 CHF2CH2CF3 1,030

HFC-365mfc 406-58-6 CH3CF2CH2CF3 794

HFC-43-10mee 138495-42-8 CF3CFHCFHCF2CF3 1,300

Sulfur hexafluoride 2551-62-4 SF6 23,900
126

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon)

Name CAS # Chemical formula

Global 

warming 

potential 

(100 yr.)

Trifluoromethyl sulphur 

pentafluoride 373-80-8

SF5CF3 17,700

Nitrogen trifluoride 7783-54-2 NF3 17,200

PFC-14 

(Perfluoromethane) 75-73-0

CF4 6,500

PFC-116 

(Perfluoroethane) 76-16-4

C2F6 9,200

PFC-218 

(Perfluoropropane) 76-19-7

C3F8 7,000

Perfluorocyclopropane 931-91-9 c-C3F6 17,340

PFC-3-1-10 

(Perfluorobutane) 355-25-9

C4F10 7,000

Perfluorocyclobutane 115-25-3 c-C4F8 8,700

PFC-4-1-12 

(Perfluoropentane) 678-26-2

C5F12 7,500

PFC-5-1-14

(Perfluorohexane) 355-42-0

C6F14 7,400

PFC-9-1-18 306-94-5 C10F18 7,500

HCFE-235da2 (Isoflurane) 26675-46-7 CHF2OCHClCF3 350

HFE-43-10pccc (H-Galden 

1040x) E1730133 CHF2OCF2OC2F4OCHF2 1,870

HFE-125 3822-68-2 CHF2OCF3 14,900

HFE-134 1691-17-4 CHF2OCHF2 6,320

HFE-143a 421-14-7 CH3OCF3 756

HFE-227ea 2356-62-9 CF3CHFOCF3 1,540

HFE-236ca12 (HG-10) 78522-47-1 CHF2OCF2OCHF2 2,800

HFE-236ea2 (Desflurane) 57041-67-5 CHF2OCHFCF3 989

HFE-236fa 20193-67-3 CF3CH2OCF3 487

HFE-245cb2 22410-44-2 CH3OCF2CF3 708

HFE-245fa1 84011-15-4 CHF2CH2OCF3 286

HFE-245fa2 1885-48-9 CHF2OCH2CF3 659

HFE-254cb2 425-88-7 CH3OCF2CHF2 359

HFE-263fb2 460-43-5 CF3CH2OCH3 11

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919

HFE-338mcf2 156053-88-2 CF3CF2OCH2CF3 552

HFE-338pcc13 (HG-01) 188690-78-0 CHF2OCF2CF2OCHF2 1,500

HFE-347mcc3 28523-86-6 CH3OCF2CF2CF3 575

HFE-347mcf2 E1730135 CF3CF2OCH2CHF2 374

HFE-347pcf2 406-78-0 CHF2CF2OCH2CF3 580

HFE-356mec3 382-34-3 CH3OCF2CHFCF3 101

HFE-356pcc3 160620-20-2 CH3OCF2CF2CHF2 110

HFE-356pcf2 E1730137 CHF2CH2OCF2CHF2 265

HFE-356pcf3 35042-99-0 CHF2OCH2CF2CHF2 502
127

Table A-1 of Subpart A—Global Warming Potentials (100-Year 

Time Horizon)

Name CAS # Chemical formula

Global 

warming 

potential 

(100 yr.)

HFE-365mcf3 378-16-5 CF3CF2CH2OCH3 11

HFE-374pc2 512-51-6 CH3CH2OCF2CHF2 557

HFE-449sl (HFE-7100)

Chemical blend

163702-07-6

163702-08-7

C4F9OCH3

(CF3)2CFCF2OCH3

297

HFE-569sf2 (HFE-7200)

Chemical blend

163702-05-4

163702-06-5

C4F9OC2H5

(CF3)2CFCF2OC2H5

59

Sevoflurane 28523-86-6 CH2FOCH(CF3)2 345

HFE-356mm1 13171-18-1 (CF3)2CHOCH3 27

HFE-338mmz1 26103-08-2 CHF2OCH(CF3)2 380

(Octafluorotetramethylene)hydroxymethyl group NA X-(CF2)4CH(OH)-X 73

HFE-347mmy1 22052-84-2 CH3OCF(CF3)2 343

Bis(trifluoromethyl)-

methanol 920-66-1 (CF3)2CHOH 195

2,2,3,3,3-

pentafluoropropanol 422-05-9 CF3CF2CH2OH 42

PFPMIE NA

CF3OCF(CF3)CF2OCF2OC

F3 10,300

NA = not available

Table A-2 of Subpart A—Units of Measure Conversions.

To convert from To Multiply by

Kilograms (kg) Pounds (lbs) 2.20462

Pounds (lbs) Kilograms (kg) 0.45359

Pounds (lbs) Metric tons 4.53592 x 10-4

Short tons Pounds (lbs) 2,000

Short tons Metric tons 0.90718

Metric tons Short tons 1.10231

Metric tons Kilograms (kg) 1,000

Cubic meters (m3) Cubic feet (ft3) 35.31467

Cubic feet (ft3) Cubic meters (m3) 0.028317

Gallons (liquid, US) Liters (l) 3.78541

Liters (l) Gallons (liquid, US) 0.26417

Barrels of Liquid 

Fuel (bbl)

Cubic meters (m3) 0.15891

Cubic meters (m3) Barrels of Liquid 

Fuel (bbl)

6.289

Barrels of Liquid 

Fuel (bbl)

Gallons (liquid, US) 42

Gallons (liquid, US) Barrels of Liquid 

Fuel (bbl)

0.023810

Gallons (liquid, US) Cubic meters (m3) 0.0037854

Liters (l) Cubic meters (m3) 0.001
128

To convert from To Multiply by

Feet (ft) Meters (m) 0.3048

Meters (m) Feet (ft) 3.28084

Miles (mi) Kilometers (km) 1.60934

Kilometers (km) Miles (mi) 0.62137

Square feet (ft2) Acres 2.29568 x 10-5

Square meters (m2) Acres 2.47105 x 10-4

Square miles (mi2) Square kilometers 

(km2)

2.58999

Degrees Celsius (oC) Degrees Fahrenheit 

(oF)

oC = (5/9) x ( oF32)

Degrees Fahrenheit 

(oF)

Degrees Celsius (oC) oF = (9/5) x oC + 32

Degrees Celsius (oC) Kelvin (K) K = oC + 273.15

Kelvin (K) Degrees Rankine (oR) 1.8

Joules Btu 9.47817 x 10-4

Btu MMBtu 1 x 10-6

Pascals (Pa) Inches of Mercury 

(in Hg)

2.95334 x 10-4

Inches of Mercury 

(inHg)

Pounds per square 

inch (psi)

0.49110

Pounds per square 

inch (psi)

Inches of Mercury

(in Hg)

2.03625

Subpart C—General Stationary Fuel Combustion Sources

§98.30 Definition of the source category. 

(a) Stationary fuel combustion sources are devices 

that combust solid, liquid, or gaseous fuel, generally for 

the purposes of producing electricity, generating steam, or 

providing useful heat or energy for industrial, commercial, 

or institutional use, or reducing the volume of waste by 

removing combustible matter. Stationary fuel combustion 

sources include, but are not limited to, boilers, simple 

and combined-cycle combustion turbines, engines, 

incinerators, and process heaters.

(b) This source category does not include:
129

(1) Portable equipment, as defined in §98.6. 

(2) Emergency generators and emergency equipment, as 

defined in §98.6.

(3) Irrigation pumps at agricultural operations.

(4) Flares, unless otherwise required by provisions 

of another subpart of this part to use methodologies in 

this subpart.

(5) Electricity generating units that are subject to 

subpart D of this part.

(c) For a unit that combusts hazardous waste (as 

defined in §261.3 of this chapter), reporting of GHG 

emissions is not required unless either of the following 

conditions apply:

(1) Continuous emission monitors (CEMS) are used to 

quantify CO2 mass emissions.

(2) Any fuel listed in Table C-1 of this subpart is 

also combusted in the unit. In this case, report GHG 

emissions from combustion of all fuels listed in Table C-1 

of this subpart.

(d) You are not required to report GHG emissions from

pilot lights. A pilot light is a small permanent auxiliary 

flame that ignites the burner of a combustion device when 

the control valve opens.

§98.31 Reporting threshold. 
130

You must report GHG emissions under this subpart if 

your facility contains one or more stationary fuel 

combustion sources and the facility meets the applicability 

requirements of either §§98.2(a)(1), 98.2(a)(2), or 

98.2(a)(3).

§98.32 GHGs to report.

You must report CO2, CH4, and N2O mass emissions from 

each stationary fuel combustion unit, except as otherwise 

indicated in this subpart. 

§98.33 Calculating GHG emissions. 

You must calculate CO2 emissions according to paragraph 

(a) of this section, and calculate CH4 and N2O emissions 

according to paragraph (c) of this section. 

(a) CO2 emissions from fuel combustion. Calculate CO2

mass emissions by using one of the four calculation 

methodologies in paragraphs (a)(1) through (a)(4) of this 

section, subject to the applicable conditions, 

requirements, and restrictions set forth in paragraph (b) 

of this section. Alternatively, for units that meet the 

conditions of paragraph (a)(5) of this section, you may use 

CO2 mass emissions calculation methods from part 75 of this 

chapter, as described in paragraph (a)(5) of this section. 

For units that combust both biomass and fossil fuels, you 

must calculate and report CO2 emissions from the combustion 
131

of biomass separately using the methods in paragraph (e) of 

this section, except as otherwise provided in paragraphs 

(a)(5)(iv) and (e) of this section and in §98.36(d).

(1) Tier 1 Calculation Methodology. Calculate the 

annual CO2 mass emissions for each type of fuel by using 

Equation C-1 or C-1a of this section (as applicable).

(i) Use Equation C-1 except when natural gas billing 

records are used to quantify fuel usage and gas consumption 

is expressed in units of therms. In that case, use 

Equation C-1a.

CO 1x 10 * Fuel *HHV *EF 3

2



 (Eq. C-1)

Where: 

CO2 = Annual CO2 mass emissions for the specific fuel 

type (metric tons). 

Fuel = Mass or volume of fuel combusted per year, from 

company records as defined in §98.6 (express mass 

in short tons for solid fuel, volume in standard 

cubic feet for gaseous fuel, and volume in 

gallons for liquid fuel).

HHV = Default high heat value of the fuel, from Table 

C-1 of this subpart (mmBtu per mass or mmBtu per 

volume, as applicable). 

EF = Fuel-specific default CO2 emission factor, from 

Table C-1 of this subpart (kg CO2/mmBtu).

1 x 10-3= Conversion factor from kilograms to metric tons.

(ii) If natural gas consumption is obtained from 

billing records and fuel usage is expressed in therms, use 

Equation C-1a.
132

CO 1 x 10 0.1* Gas * EF

3

2



 (Eq. C-1a)

Where:

CO2 = Annual CO2 mass emissions from natural gas 

combustion (metric tons). 

Gas = Annual natural gas consumption, from billing 

records (therms). 

EF = Fuel-specific default CO2 emission factor for 

natural gas, from Table C-1 of this subpart 

(kg CO2/mmBtu).

0.1 = Conversion factor from therms to mmBtu

1 x 10-3= Conversion factor from kilograms to metric tons.

(2) Tier 2 Calculation Methodology. Calculate the 

annual CO2 mass emissions for each type of fuel by using 

either Equation C2a or C2c of this section, as appropriate. 

(i) Equation C-2a of this section applies to any type 

of fuel listed in Table C-1 of the subpart, except for 

municipal solid waste (MSW). For MSW combustion, use 

Equation C-2c of this section. 

CO 1x 10 * Fuel *HHV *EF 3

2



 (Eq. C-2a)

Where: 

CO2 = Annual CO2 mass emissions for a specific fuel 

type (metric tons). 

Fuel = Mass or volume of the fuel combusted during the 

year, from company records as defined in §98.6 

(express mass in short tons for solid fuel,

volume in standard cubic feet for gaseous fuel, 

and volume in gallons for liquid fuel).

HHV = Annual average high heat value of the fuel

(mmBtu per mass or volume). The average HHV 

shall be calculated according to the 

requirements of paragraph (a)(2)(ii) of this 

section.
133

EF = Fuel-specific default CO2 emission factor, from 

Table C-1 of this subpart (kg CO2/mmBtu).

1 x 10-3 = Conversion factor from kilograms to metric 

tons.

(ii) The minimum required sampling frequency for 

determining the annual average HHV (e.g., monthly, 

quarterly, semi-annually, or by lot) is specified in 

§98.34. The method for computing the annual average HHV is 

a function of unit size and how frequently you perform or 

receive from the fuel supplier the results of fuel sampling 

for HHV. The method is specified in paragraph 

(a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as 

applicable.

(A) If the results of fuel sampling are received 

monthly or more frequently, then for each unit with a 

maximum rated heat input capacity greater than or equal to 

100 mmBtu/hr (or for a group of units that includes at 

least one unit of that size), the annual average HHV shall 

be calculated using Equation C-2b of this section. If 

multiple HHV determinations are made in any month, average 

the values for the month arithmetically.

 

   

 









 n

i

i

n

i

i i

annual

Fuel

HHV Fuel

HHV

1

1 (Eq. C-2b)

Where:
134

(HHV)annual = Weighted annual average high heat value of the 

fuel (mmBtu per mass or volume).

(HHV)i = Measured high heat value of the fuel, for month 

“i”, or, if applicable, an appropriate 

substitute data value (mmBtu per mass or 

volume).

(Fuel)i = Mass or volume of the fuel combusted during 

month “i,” from company records (express mass 

in short tons for solid fuel, volume in 

standard cubic feet for gaseous fuel, and 

volume in gallons for liquid fuel).

n = Number of months in the year that the fuel is 

burned in the unit.

(B) If the results of fuel sampling are received less 

frequently than monthly, or, for a unit with a maximum 

rated heat input capacity less than 100 mmBtu/hr (or a 

group of such units) regardless of the HHV sampling 

frequency, the annual average HHV shall be computed as the 

arithmetic average HHV for all values for the year 

(including valid samples and substitute data values under 

§98.35). 

(iii) For units that combust municipal solid waste 

(MSW) and that produce steam, use Equation C-2c of this 

section. Equation C-2c of this section may also be used 

for any other solid fuel listed in Table C-1 of this 

subpart provided that steam is generated by the unit. 

CO  x Steam BEF 3

2

1 10 (Eq. C-2c)

Where:
135

CO2 = Annual CO2 mass emissions from MSW or solid 

fuel combustion (metric tons).

Steam = Total mass of steam generated by MSW or solid 

fuel combustion during the reporting year (lb 

steam).

B = Ratio of the boiler’s maximum rated heat input 

capacity to its design rated steam output 

capacity (mmBtu/lb steam).

EF = Fuel-specific default CO2 emission factor, 

from Table C-1 of this subpart (kg CO2/mmBtu).

1 x 10-3 = Conversion factor from kilograms to metric 

tons.

(3) Tier 3 Calculation Methodology. Calculate the 

annual CO2 mass emissions for each fuel by using either 

Equation C3, C4, or C5 of this section, as appropriate.

(i) For a solid fuel, use Equation C-3 of this 

section.

0.91

12

44

2 CO   Fuel  CC  (Eq. C-3)

Where: 

CO2 = Annual CO2 mass emissions from the combustion 

of the specific solid fuel (metric tons). 

Fuel = Annual mass of the solid fuel combusted, from 

company records as defined in §98.6 (short 

tons). 

CC = Annual average carbon content of the solid fuel 

(percent by weight, expressed as a decimal 

fraction, e.g., 95% = 0.95). The annual 

average carbon content shall be determined 

using the same procedures as specified for HHV 

in paragraph (a)(2)(ii) of this section.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.91 = Conversion factor from short tons to metric 

tons.
136

(ii) For a liquid fuel, use Equation C-4 of this 

section.

Fuel CC 0.001

12

44 CO2     (Eq. C-4)

Where: 

CO2 = Annual CO2 mass emissions from the combustion 

of the specific liquid fuel (metric tons). 

Fuel = Annual volume of the liquid fuel combusted 

(gallons). The volume of fuel combusted must 

be measured directly, using fuel flow meters 

calibrated according to §98.3(i). Fuel 

billing meters may be used for this purpose. 

Tank drop measurements may also be used.

CC = Annual average carbon content of the liquid 

fuel (kg C per gallon of fuel). The annual 

average carbon content shall be determined 

using the same procedures as specified for HHV 

in paragraph (a)(2)(ii) of this section.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(iii) For a gaseous fuel, use Equation C-5 of this 

section.

0.001

12

44

2     

MVC

MW CO Fuel CC (Eq. C-5)

Where: 

CO2 = Annual CO2 mass emissions from combustion of 

the specific gaseous fuel (metric tons).

Fuel = Annual volume of the gaseous fuel combusted 

(scf). The volume of fuel combusted must be 

measured directly, using fuel flow meters 

calibrated according to §98.3(i). Fuel 

billing meters may be used for this purpose.

CC = Annual average carbon content of the gaseous 

fuel (kg C per kg of fuel). The annual 
137

average carbon content shall be determined 

using the same procedures as specified for HHV 

in paragraph (a)(2)(ii) of this section.

MW = Annual average molecular weight of the gaseous 

fuel (kg/kg-mole). The annual average 

molecular weight shall be determined using the 

same procedures as specified for HHV in 

paragraph (a)(2)(ii) of this section.

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions, as defined in 

§98.6).

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(iv) Fuel flow meters that measure mass flow rates 

may be used for liquid or gaseous fuels, provided that the 

fuel density is used to convert the readings to volumetric 

flow rates. The density shall be measured at the same 

frequency as the carbon content. For liquid fuels, you 

must measure the density using one of the following 

appropriate methods. You may use a method published by a 

consensus standards organization, if such a method exists, 

or you may use industry standard practice. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). The method(s) 
138

used shall be documented in the Monitoring Plan required 

under §98.3(g)(5). Alternatively, for fuel oil, you may

use an applicable default density value provided in 

paragraph (a)(3)(v) of this section. For gaseous fuels, 

you may determine the density using any of the following 

methods. You may use a density meter calibrated according 

to the manufacturer’s instructions, a method published by a 

consensus standards organization, or an industry standard 

practice. Document the method used to determine the fuel 

density in the Monitoring Plan under §98.3(g)(5).

(v) The following default density values may be used 

for fuel oil, in lieu of using the ASTM method in paragraph 

(a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 

lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil.

(4) Tier 4 Calculation Methodology. Calculate the 

annual CO2 mass emissions from all fuels combusted in a 

unit, by using quality-assured data from continuous 

emission monitoring systems (CEMS). 

(i) This methodology requires a CO2 concentration 

monitor and a stack gas volumetric flow rate monitor, 

except as otherwise provided in paragraph (a)(4)(iv) of 

this section. Hourly measurements of CO2 concentration and 

stack gas flow rate are converted to CO2 mass emission rates 

in metric tons per hour. 
139

(ii) When the CO2 concentration is measured on a wet 

basis, Equation C-6 of this section is used to calculate 

the hourly CO2 emission rates:

CO 5.18 x10 * CCO2* Q

7

2



 (Eq. C-6)

Where: 

CO2 = CO2 mass emission rate (metric tons/hr). 

CCO2 = Hourly average CO2 concentration (% CO2).

Q = Hourly average stack gas volumetric flow 

rate (scfh).

5.18 x 10-7 = Conversion factor (metric tons/scf/% CO2).

(iii) If the CO2 concentration is measured on a dry 

basis, a correction for the stack gas moisture content is 

required. You shall either continuously monitor the stack 

gas moisture content as described in §75.11(b)(2) of this 

chapter or use an appropriate default moisture percentage. 

For coal, wood, and natural gas combustion, you may use the 

default moisture values specified in §75.11(b)(1) of this 

chapter. Alternatively, for any type of fuel, you may 

determine an appropriate site-specific default moisture 

value (or values), using measurements made with EPA Method 

4 - Determination Of Moisture Content In Stack Gases, in 

appendix A-3 to part 60 of this chapter. If this option is 

selected, the site-specific moisture default value(s) must 

represent the fuel(s) or fuel blends that are combusted in 

the unit during normal, stable operation, and must account 
140

for any distinct difference(s) in the stack gas moisture 

content associated with different process operating 

conditions. For each site-specific default moisture 

percentage, at least nine Method 4 runs are required. 

Moisture data from the relative accuracy test audit (RATA) 

of a CEMS may be used for this purpose. Calculate each 

site-specific default moisture value by taking the 

arithmetic average of the Method 4 runs. Each sitespecific moisture default value shall be updated whenever 

the owner or operator believes the current value is nonrepresentative, due to changes in unit or process 

operation, but in any event no less frequently than 

annually. Use the updated moisture value in the subsequent 

CO2 emissions calculations. For each unit operating hour, a 

moisture correction must be applied to Equation C-6 of this 

section as follows:











 



100

100 % 2

2

*

2

H O

CO CO (Eq. C-7)

Where: 

CO2

* = Hourly CO2 mass emission rate, corrected for 

moisture (metric tons/hr).

CO2 = Hourly CO2 mass emission rate from Equation C-6 of 

this section, uncorrected (metric tons/hr). 

%H2O = Hourly moisture percentage in the stack gas 

(measured or default value, as appropriate). 
141

(iv) An oxygen (O2) concentration monitor may be used 

in lieu of a CO2 concentration monitor to determine the 

hourly CO2 concentrations, in accordance with Equation F-14a 

or F-14b (as applicable) in appendix F to part 75 of this 

chapter, if the effluent gas stream monitored by the CEMS 

consists solely of combustion products (i.e., no process CO2

emissions or CO2 emissions from sorbent are mixed with the

combustion products) and if only fuels that are listed in 

Table 1 in section 3.3.5 of appendix F to part 75 of this 

chapter are combusted in the unit. If the O2 monitoring 

option is selected, the F-factors used in Equations F-14a 

and F-14b shall be determined according to section 3.3.5 or 

section 3.3.6 of appendix F to part 75 of this chapter, as 

applicable. If Equation F-14b is used, the hourly moisture 

percentage in the stack gas shall be determined in 

accordance with paragraph (a)(4)(iii) of this section.

(v) Each hourly CO2 mass emission rate from Equation 

C-6 or C-7 of this section is multiplied by the operating 

time to convert it from metric tons per hour to metric 

tons. The operating time is the fraction of the hour 

during which fuel is combusted (e.g., the unit operating 

time is 1.0 if the unit operates for the whole hour and is 

0.5 if the unit operates for 30 minutes in the hour). For 

common stack configurations, the operating time is the 
142

fraction of the hour during which effluent gases flow 

through the common stack. 

(vi) The hourly CO2 mass emissions are then summed 

over each calendar quarter and the quarterly totals are 

summed to determine the annual CO2 mass emissions.

(vii) If both biomass and fossil fuel are combusted 

during the year, determine and report the biogenic CO2 mass 

emissions separately, as described in paragraph (e) of this 

section.

(viii) If a portion of the flue gases generated by a 

unit subject to Tier 4 (e.g., a slip stream) is 

continuously diverted from the main flue gas exhaust system 

for the purpose of heat recovery or some other similar 

process, and then exhausts through a stack that is not 

equipped with the continuous emission monitors to measure 

CO2 mass emissions, provided that the CO2 concentration in 

the diverted stream is not altered in any way (e.g., by 

chemical reaction or dilution) before the diverted stream 

exits to the atmosphere, an estimate of the hourly average 

volumetric flow rate (scfh) of the diverted gas stream 

shall be made at the point where it exits the main exhaust 

system, by using the best available information (e.g., 

correlations of operating parameters versus flow 

measurements made with EPA Method 2 in appendix A-2 to part 
143

60 of this chapter, engineering analysis, or other 

methods). Each hourly average volumetric flow rate (scfh) 

measured at the main flue gas stack shall then be added to 

the corresponding estimate of the hourly average flow rate 

of the diverted gas stream, to determine the total hourly 

average stack gas volumetric flow rate "Q", for use in 

Equation C-6 of this section. The method use to estimate 

the hourly flow rate of the diverted portion of the flue 

gas exhaust stream shall be documented in the Monitoring 

Plan required under §98.3(g)(5).

(5) Alternative methods for certain units subject to 

Part 75 of this chapter. Certain units that are not 

subject to subpart D of this part and that report data to 

EPA according to part 75 of this chapter may qualify to use 

the alternative methods in this paragraph (a)(5), in lieu 

of using any of the four calculation methodology tiers.

(i) For a unit that combusts only natural gas and/or 

fuel oil, is not subject to subpart D of this part, 

monitors and reports heat input data year-round according 

to appendix D to part 75 of this chapter, but is not 

required by the applicable part 75 program to report CO2

mass emissions data, calculate the annual CO2 mass emissions 

for the purposes of this part as follows: 
144

(A) Use the hourly heat input data from appendix D to 

part 75 of this chapter, together with Equation G-4 in 

appendix G to part 75 of this chapter to determine the 

hourly CO2 mass emission rates, in units of tons/hr; 

(B) Use Equations F-12 and F-13 in appendix F to part 

75 of this chapterto calculate the quarterly and cumulative 

annual CO2 mass emissions, respectively, in units of short 

tons; and 

(C) Divide the cumulative annual CO2 mass emissions 

value by 1.1 to convert it to metric tons.

(ii) For a unit that combusts only natural gas and/or

fuel oil, is not subject to subpart D of this part, 

monitors and reports heat input data year-round according 

to §75.19 of this chapter but is not required by the 

applicable part 75 program to report CO2 mass emissions 

data, calculate the annual CO2 mass emissions for the 

purposes of this part as follows:

(A) Calculate the hourly CO2 mass emissions, in units 

of short tons, using Equation LM-11 in §75.19(c)(4)(iii) of 

this chapter.

(B) Sum the hourly CO2 mass emissions values over the 

entire reporting year to obtain the cumulative annual CO2

mass emissions, in units of short tons.
145

(C) Divide the cumulative annual CO2 mass emissions 

value by 1.1 to convert it to metric tons.

(iii) For a unit that is not subject to subpart D of 

this part, uses flow rate and CO2 (or O2) CEMS to report 

heat input data year-round according to part 75 of this 

chapter, but is not required by the applicable part 75 

program to report CO2 mass emissions data, calculate the 

annual CO2 mass emissions as follows:

(A) Use Equation F-11 or F-2 (as applicable) in 

appendix F to part 75 of this chapter to calculate the 

hourly CO2 mass emission rates from the CEMS data. If an O2

monitor is used, convert the hourly average O2 readings to 

CO2 using Equation F-14a or F-14b in appendix F to part 75 

of this chapter (as applicable), before applying Equation 

F-11 or F-2.

(B) Use Equations F-12 and F-13 in appendix F to part 

75 of this chapter to calculate the quarterly and 

cumulative annual CO2 mass emissions, respectively, in units 

of short tons. 

(C) Divide the cumulative annual CO2 mass emissions 

value by 1.1 to convert it to metric tons.

(iv) For units that qualify to use the alternative CO2

emissions calculation methods in paragraphs (a)(5)(i) 

through (a)(5)(iii) of this section, if both biomass and 
146

fossil fuel are combusted during the year, separate 

calculation and reporting of the biogenic CO2 mass emissions 

(as described in paragraph (e) of this section) is 

optional. 

(b) Use of the four tiers. Use of the four tiers of 

CO2 emissions calculation methodologies described in 

paragraph (a) of this section is subject to the following 

conditions, requirements, and restrictions:

(1) The Tier 1 Calculation Methodology:

(i) May be used for any fuel listed in Table C-1 of 

this subpart that is combusted in a unit with a maximum 

rated heat input capacity of 250 mmBtu/hr or less. 

(ii) May be used for MSW in a unit of any size that 

does not produce steam, if the use of Tier 4 is not 

required. 

(iii) May be used for solid, gaseous, or liquid 

biomass fuels in a unit of any size provided that the fuel 

is listed in Table C-1 of this subpart.

(iv) May not be used if you routinely perform fuel 

sampling and analysis for the fuel high heat value (HHV) or 

routinely receive the results of HHV sampling and analysis 

from the fuel supplier at the minimum frequency specified 

in §98.34(a), or at a greater frequency. In such cases, 
147

Tier 2 shall be used. This restriction does not apply to 

paragraphs (b)(1)(ii) and (b)(1)(v) of this section.

(v) May be used for natural gas combustion in a unit 

of any size, in cases where the annual natural gas 

consumption is obtained from fuel billing records in units 

of therms. 

(2) The Tier 2 Calculation Methodology:

(i) May be used for the combustion of any type of 

fuel in a unit with a maximum rated heat input capacity of 

250 mmBtu/hr or less provided that the fuel is listed in 

Table C-1 of this subpart.

(ii) May be used in a unit with a maximum rated heat 

input capacity greater than 250 mmBtu/hr for the combustion 

of natural gas and/or distillate fuel oil. 

(iii) May be used for MSW in a unit of any size that 

produces steam, if the use of Tier 4 is not required. 

(3) The Tier 3 Calculation Methodology:

(i) May be used for a unit of any size that combusts 

any type of fuel listed in Table C-1 of this subpart 

(except for MSW), unless the use of Tier 4 is required. 

(ii) Shall be used for a unit with a maximum rated 

heat input capacity greater than 250 mmBtu/hr that combusts 

any type of fuel listed in Table C-1 of this subpart 
148

(except MSW), unless either of the following conditions 

apply:

(A) The use of Tier 1 or 2 is permitted, as described 

in paragraphs (b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of 

this section.

(B) The use of Tier 4 is required. 

(iii) Shall be used for a fuel not listed in Table C1 of this subpart if the fuel is combusted in a unit with a 

maximum rated heat input capacity greater than 250 mmBtu/hr

(or, pursuant to §98.36(c)(3), in a group of units served 

by a common supply pipe, having at least one unit with a 

maximum rated heat input capacity greater than 250 

mmBtu/hr), provided that both of the following conditions 

apply:

(A) The use of Tier 4 is not required.

(B) The fuel provides 10% or more of the annual heat 

input to the unit or, if §98.36(c)(3)applies, to the group 

of units served by a common supply pipe.

(iv) Shall be used when specified in another 

applicable subpart of this part, regardless of unit size.

(4) The Tier 4 Calculation Methodology:

(i) May be used for a unit of any size, combusting 

any type of fuel. Tier 4 may also be used for any group of 
149

stationary fuel combustion units, process units, or 

manufacturing units that share a common stack or duct.

(ii) Shall be used if the unit meets all six of the 

conditions specified in paragraphs (b)(4)(ii)(A) through 

(b)(4)(ii)(F) of this section:

(A) The unit has a maximum rated heat input capacity 

greater than 250 mmBtu/hr, or if the unit combusts 

municipal solid waste and has a maximum rated input 

capacity greater than 600 tons per day of MSW. 

(B) The unit combusts solid fossil fuel or MSW as the 

primary fuel.

(C) The unit has operated for more than 1,000 hours 

in any calendar year since 2005.

(D) The unit has installed CEMS that are required 

either by an applicable Federal or State regulation or the 

unit’s operating permit.

(E) The installed CEMS include a gas monitor of any 

kind or a stack gas volumetric flow rate monitor, or both 

and the monitors have been certified, either in accordance 

with the requirements of part 75 of this chapter, part 60 

of this chapter, or an applicable State continuous 

monitoring program.

(F) The installed gas or stack gas volumetric flow 

rate monitors are required, either by an applicable Federal 
150

or State regulation or by the unit’s operating permit, to 

undergo periodic quality assurance testing in accordance 

with either appendix B to part 75 of this chapter, appendix 

F to part 60 of this chapter, or an applicable State 

continuous monitoring program.

(iii) Shall be used for a unit with a maximum rated 

heat input capacity of 250 mmBtu/hr or less and for a unit 

that combusts municipal solid waste with a maximum rated 

input capacity of 600 tons of MSW per day or less, if the 

unit meets all of the following three conditions:

(A) The unit has both a stack gas volumetric flow 

rate monitor and a CO2 concentration monitor.

(B) The unit meets the conditions specified in 

paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this 

section.

(C) The CO2 and stack gas volumetric flow rate 

monitors meet the conditions specified in paragraphs 

(b)(4)(ii)(E) and (b)(4)(ii)(F) of this section. 

(iv) May apply to common stack or duct configurations

where:

(A) The combined effluent gas streams from two or 

more stationary fuel combustion units are vented through a 

monitored common stack or duct. In this case, Tier 4 shall 

be used if all of the conditions in paragraph 
151

(b)(4)(iv)(A)(1) of this section or all of the conditions 

in paragraph (b)(4)(iv)(A)(2) of this section are met.

(1) At least one of the units meets the requirements 

of paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(C) of this 

section, and the CEMS installed at the common stack (or 

duct) meet the requirements of paragraphs (b)(4)(ii)(D) 

through (b)(4)(ii)(F) of this section.

(2) At least one of the units and the monitors 

installed at the common stack or duct meet the requirements 

of paragraph (b)(4)(iii) of this section. 

(B) The combined effluent gas streams from a process 

or manufacturing unit and a stationary fuel combustion unit 

are vented through a monitored common stack or duct. In 

this case, Tier 4 shall be used if the combustion unit and 

the monitors installed at the common stack or duct meet the 

applicability criteria specified in paragraph 

(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section. 

(C) The combined effluent gas streams from two or 

more manufacturing or process units are vented through a 

common stack or duct. In this case, if any of the units is 

required by an applicable subpart of this part to use Tier 

4, the CO2 mass emissions may either be monitored at each 

individual unit, or the combined CO2 mass emissions may be 

monitored at the common stack or duct. However, if it is 
152

not feasible to monitor the individual units, the combined 

CO2 mass emissions shall be monitored at the common stack or 

duct.

(5) The Tier 4 Calculation Methodology shall be used:

(i) Starting on January 1, 2010, for a unit that is 

required to report CO2 mass emissions beginning on that 

date, if all of the monitors needed to measure CO2 mass 

emissions have been installed and certified by that date.

(ii) No later than January 1, 2011, for a unit that 

is required to report CO2 mass emissions beginning on 

January 1, 2010, if all of the monitors needed to measure 

CO2 mass emissions have not been installed and certified by 

January 1, 2010. In this case, you may use Tier 2 or Tier 

3 to report GHG emissions for 2010. However, if the 

required CEMS are certified some time in 2010, you need not 

wait until January 1, 2011 to begin using Tier 4. Rather, 

you may switch from Tier 2 or Tier 3 to Tier 4 as soon as 

CEMS certification testing is successfully completed. If 

this reporting option is chosen, you must document the 

change in CO2 calculation methodology in the Monitoring Plan 

required under §98.3(g)(5) and in the GHG emissions report 

under §98.3(c). Data recorded by the CEMS during a 

certification test period in 2010 may be used for reporting 
153

under this part, provided that the following two conditions 

are met:

(A) The certification tests are passed in sequence, 

with no test failures.

(B) No unscheduled maintenance or repair of the CEMS 

is performed during the certification test period. 

(iii) No later than 180 days following the date on 

which a change is made that triggers Tier 4 applicability 

under paragraph (b)(4)(ii) or (b)(4)(iii) of this section 

(e.g., a change in the primary fuel, manner of unit 

operation, or installed continuous monitoring equipment). 

(6) You may elect to use any applicable higher tier 

for one or more of the fuels combusted in a unit. For 

example, if a 100 mmBtu/hr unit combusts natural gas and 

distillate fuel oil, you may elect to use Tier 1 for 

natural gas and Tier 3 for the fuel oil, even though Tier 1 

could have been used for both fuels. However, for units 

that use either the Tier 4 or the alternative calculation 

methodology specified in paragraph (a)(5)(iii) of this 

section, CO2 emissions from the combustion of all fuels 

shall be based solely on CEMS measurements. 

(c) Calculation of CH4 and N2O emissions from 

stationary combustion sources. You must calculate annual 

CH4 and N2O mass emissions only for units that are required 
154

to report CO2 emissions using the calculation methodologies 

of this subpart and for only those fuels that are listed in 

Table C-2 of this subpart.

(1) Use Equation C-8 of this section to estimate CH4

and N2O emissions for any fuels for which you use the Tier 1 

or Tier 3 calculation methodologies for CO2. Use the same 

values for fuel consumption that you use for the Tier 1 or 

Tier 3 calculation.

CH or N O 1 x 10 * Fuel * HHV * EF 3

4 2



 (Eq. C-8)

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from the 

combustion of a particular type of fuel 

(metric tons).

Fuel = Mass or volume of the fuel combusted, either 

from company records or directly measured by a

fuel flow meter, as applicable (mass or volume 

per year).

HHV = Default high heat value of the fuel from Table 

C-1 of this subpart; alternatively, for Tier 

3, if actual HHV data are available for the 

reporting year, you may average these data 

using the procedures specified in paragraph 

(a)(2)(ii) of this section, and use the 

average value in Equation C-8 (mmBtu per mass 

or volume).

EF = Fuel-specific default emission factor for CH4

or N2O, from Table C-2 of this subpart (kg CH4

or N2O per mmBtu).

1 x 10-3 = Conversion factor from kilograms to metric 

tons.

(2) Use Equation C-9a of this section to estimate CH4

and N2O emissions for any fuels for which you use the Tier 2 
155

Equation C-2a of this section to estimate CO2 emissions. 

Use the same values for fuel consumption and HHV that you 

use for the Tier 2 calculation.

CH or N O 1 x 10 * HHV * EF * Fuel 3

4 2



 (Eq. C-9a)

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from the combustion 

of a particular type of fuel (metric tons).

Fuel = Mass or volume of the fuel combusted during the 

reporting year.

HHV = High heat value of the fuel, averaged for all 

valid measurements for the reporting year 

(mmBtu per mass or volume).

EF = Fuel-specific default emission factor for CH4

or N2O, from Table C-2 of this subpart (kg CH4

or N2O per mmBtu).

1 x 10-3 = Conversion factor from kilograms to metric 

tons. 

(3) Use Equation C-9b of this section to estimate CH4

and N2O emissions for any fuels for which you use Equation 

C-2c of this section to calculate the CO2 emissions. Use 

the same values for steam generation and the ratio “B” that 

you use for Equation C-2c. 

CH or N O  x Steam B EF 3

4 2

1 10 (Eq. C-9b)

Where:

CH4 or N2O = Annual CH4 or N2O emissions from the 

combustion of a solid fuel (metric tons).

Steam = Total mass of steam generated by solid fuel 

combustion during the reporting year (lb 

steam).
156

B = Ratio of the boiler’s maximum rated heat input 

capacity to its design rated steam output 

(mmBtu/lb steam).

EF = Fuel-specific emission factor for CH4 or N2O, 

from Table C-2 of this subpart (kg CH4 or N2O 

per mmBtu).

1 x 10-3 = Conversion factor from kilograms to metric 

tons. 

(4) Use Equation C-10 of this section for: units 

subject to subpart D of this part; units that qualify for 

and elect to use the alternative CO2 mass emissions 

calculation methodologies described in paragraph (a)(5) of 

this section;, and units that use the Tier 4 Calculation 

Methodology. 

CH4or N2O  0.001* HIA* EF (Eq. C-10)

Where: 

CH4 or N2O = Annual CH4 or N2O emissions from the 

combustion of a particular type of fuel 

(metric tons).

(HI)A = Cumulative annual heat input from combustion 

of the fuel (mmBtu).

EF = Fuel-specific emission factor for CH4 or N2O, 

from Table C-2 of this section (kg CH4 or N2O 

per mmBtu).

0.001 = Conversion factor from kg to metric tons.

(i) If only one type of fuel listed in Table C-2 of 

this subpart is combusted during the reporting year, 

substitute the cumulative annual heat input from combustion 

of the fuel into Equation C-10 of this section to calculate 

the annual CH4 or N2O emissions. For units in the Acid 
157

Rain Program and units that report heat input data to EPA 

year-round according to part 75 of this chapter, obtain the 

cumulative annual heat input directly from the electronic 

data reports required under §75.64 of this chapter. For 

Tier 4 units, use the best available information, as 

described in paragraph (c)(4)(ii)(C) of this section, to 

estimate the cumulative annual heat input (HI)A. 

(ii) If more than one type of fuel listed in Table C2 of this subpart is combusted during the reporting year, 

use Equation C-10 of this section separately for each type 

of fuel, except as provided in paragraph (c)(4)(ii)(B) of 

this section. Determine the appropriate values of (HI)A as 

follows: 

(A) For units in the Acid Rain Program and other 

units that report heat input data to EPA year-round 

according to part 75 of this chapter, obtain (HI)A for each 

type of fuel from the electronic data reports required 

under §75.64 of this chapter, except as otherwise provided 

in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this 

section. 

(B) For a unit that uses CEMS to monitor hourly heat 

input according to part 75 of this chapter, the value of 

(HI)A obtained from the electronic data reports under §75.64 

of this chapter may be attributed exclusively to the fuel 
158

with the highest F-factor, when the reporting option in 

3.3.6.5 of appendix F to part 75 of this chapter is 

selected and implemented. 

(C) For Tier 4 units, use the best available 

information (e.g., fuel feed rate measurements, fuel 

heating values, engineering analysis) to estimate the value 

of (HI)A for each type of fuel. Instrumentation used to 

make these estimates is not subject to the calibration 

requirements of §98.3(i) or to the QA requirements of 

§98.34. 

(D) Units in the Acid Rain Program and other units 

that report heat input data to EPA year-round according to 

part 75 of this chapter may use the best available 

information described in paragraph (c)(4)(ii)(C) of this 

section, to estimate (HI)A for each fuel type, whenever 

fuel-specific heat input values cannot be directly obtained 

from the electronic data reports under §75.64 of this 

chapter. 

(5) When multiple fuels are combusted during the 

reporting year, sum the fuel-specific results from 

Equations C-8, C-9a, C-9b, or C-10 of this section (as 

applicable) to obtain the total annual CH4 and N2O 

emissions, in metric tons. 
159

(6) Calculate the annual CH4 and N2O mass emissions 

from the combustion of blended fuels as follows: 

(i) If the mass or volume of each component fuel in 

the blend is measured before the fuels are mixed and 

combusted, calculate and report CH4 and N2O emissions 

separately for each component fuel, using the applicable 

procedures in this paragraph (c). 

(ii) If the mass or volume of each component fuel in 

the blend is not measured before the fuels are mixed and 

combusted, a reasonable estimate of the percentage 

composition of the blend, based on best available 

information, is required. Perform the following 

calculations for each component fuel, “i”, that is listed 

in Table C-2:

(A) Multiply (% Fuel)i, the estimated mass or volume 

percentage (decimal fraction) of component fuel “i”, by the 

total annual mass or volume of the blended fuel combusted 

during the reporting year, to obtain an estimate of the 

annual consumption of component “i”;

(B) Multiply the result from paragraph (c)(6)(ii)(A) 

of this section by the HHV of the fuel (default value or, 

if available, the measured annual average value), to obtain 

an estimate of the annual heat input from component “i”;
160

(C) Calculate the annual CH4 and N2O emissions from 

component “i”, using Equation C-8, C-9a, or C-10 of this 

section, as applicable;

(D) Sum the annual CH4 emissions across all component 

fuels to obtain the annual CH4 emissions for the blend. 

Similarly sum the annual N2O emissions across all component 

fuels to obtain the annual N2O emissions for the blend. 

Report these annual emissions totals. 

(d) Calculation of CO2 from sorbent.

(1) When a unit is a fluidized bed boiler, is 

equipped with a wet flue gas desulfurization system, or 

uses other acid gas emission controls with sorbent 

injection to remove acid gases, if the chemical reaction 

between the acid gas and the sorbent produces CO2 emissions, 

use Equation C-11 of this section to calculate the CO2

emissions from the sorbent, except when those CO2 emissions 

are monitored by CEMS. When a sorbent other than CaCO3 is 

used, determine site-specific values of R and MWS.



















S

CO

MW

MW CO S R

2

2

0.91* * * (Eq. C-11)

Where: 

CO2 = CO2 emitted from sorbent for the reporting year 

(metric tons).

S = Limestone or other sorbent used in the reporting 

year, from company records (short tons).
161

R = The number of moles of CO2 released upon capture of 

one mole of the acid gas species being removed (R = 

1.00 when the sorbent is CaCO3 and the targeted 

acid gas species is SO2). 

MWCO2 = Molecular weight of carbon dioxide (44).

MWS = Molecular weight of sorbent (100 if calcium 

carbonate).

0.91 = Conversion factor from short tons to metric tons

(2) The total annual CO2 mass emissions reported for 

the unit shall include the CO2 emissions from the combustion 

process and the CO2 emissions from the sorbent. 

(e) Biogenic CO2 emissions from combustion of biomass

with other fuels. Use the applicable procedures of this 

paragraph (e) to estimate biogenic CO2 emissions from units 

that combust a combination of biomass and fossil fuels

(i.e., either co-fired or blended fuels). Separate 

reporting of biogenic CO2 emissions from the combined 

combustion of biomass and fossil fuels is required for 

those biomass fuels listed in Table C-1 of this section and 

for municipal solid waste. In addition, when a biomass 

fuel that is not listed in Table C-1 is combusted in a unit 

that has a maximum rated heat input greater than 250 

mmBtu/hr, if the biomass fuel accounts for 10% or more of 

the annual heat input to the unit, and if the unit does not 

use CEMS to quantify its annual CO2 mass emissions, then, 

pursuant to §98.33(b)(3)(iii), Tier 3 must be used to 
162

determine the carbon content of the biomass fuel and to 

calculate the biogenic CO2 emissions from combustion of the 

fuel. Notwithstanding these requirements, separate 

reporting of biogenic CO2 emissions is optional for units 

subject to subpart D of this part and for units that use 

the CO2 mass emissions calculation methodologies in part 75 

of this chapter, pursuant to paragraph (a)(5) of this 

section; however, if the owner or operator opts to report 

biogenic CO2 emissions separately for these units, the 

appropriate method(s) in this paragraph (e) shall be used. 

Separate reporting of biogenic CO2 emissions from the 

combustion of tires is also optional, but may be reported 

by following the provisons of paragraph (e)(3) of this 

section.

(1) You may use Equation C-1 of this subpart to 

calculate the annual CO2 mass emissions from the combustion 

of the biomass fuels listed in Table C-1 of this subpart

(except MSW and tires), in a unit of any size, including 

units equipped with a CO2 CEMS, except when the use of Tier 

2 is required as specified in paragraph (b)(1)(iv) of this 

section. Determine the quantity of biomass combusted using 

one of the following procedures in this paragraph (e)(1), 

as appropriate, and document the selected procedures in the 

Monitoring Plan under §98.3(g):
163

(i) Company records.

(ii) The procedures in paragraph (e)(5) of this 

section.

(iii) The best available information for premixed 

fuels that contain biomass and fossil fuels (e.g., liquid 

fuel mixtures containing biodiesel). 

(2) You may use the procedures of this paragraph if

the following three conditions are met: first, a CO2 CEMS 

(or a surrogate O2 monitor) and a stack gas flow rate 

monitor are used to determine the annual CO2 mass emissions 

(either according to part 75 of this chapter, the Tier 4 

Calculation Methodology, or the alternative calculation 

methodology specified in paragraph (a)(5)(iii) of this 

section); second, neither MSW nor tires is combusted in the 

unit during the reporting year; and third, the CO2 emissions 

consist solely of combustion products (i.e., no process or 

sorbent emissions included).

(i) For each operating hour, use Equation C-12 of 

this section to determine the volume of CO2 emitted.

 

h h

h

CO h Q t

CO

V * *

100

% 2

2  (Eq. C-12)

Where:

VCO2h = Hourly volume of CO2 emitted (scf).

(%CO2)h = Hourly average CO2 concentration, measured by the 

CO2 concentration monitor, or, if applicable, 
164

calculated from the hourly average O2 

concentration (%CO2).

Qh = Hourly average stack gas volumetric flow rate, 

measured by the stack gas volumetric flow rate 

monitor (scfh).

th = Source operating time (decimal fraction of the 

hour during which the source combusts fuel, 

i.e., 1.0 for a full operating hour, 0.5 for 30 

minutes of operation, etc.).

100 = Conversion factor from percent to a decimal 

fraction.

(ii) Sum all of the hourly VCO2h values for the 

reporting year, to obtain Vtotal, the total annual volume of 

CO2 emitted.

(iii) Calculate the annual volume of CO2 emitted from 

fossil fuel combustion using Equation C-13 of this section. 

If two or more types of fossil fuel are combusted during 

the year, perform a separate calculation with Equation C-13 

of this section for each fuel and sum the results. 

6

c

ff 10

Fuel * F * HHV V  (Eq. C-13)

Where: 

Vff = Annual volume of CO2 emitted from combustion of a 

particular fossil fuel (scf).

Fuel = Total quantity of the fossil fuel combusted in the 

reporting year, from company records, as defined in 

§98.6 (lb for solid fuel, gallons for liquid fuel, 

and scf for gaseous fuel).

Fc = Fuel-specific carbon based F-factor, either a 

default value from Table 1 in section 3.3.5 of 

appendix F to part 75 of this chapter, or a sitespecific value determined under section 3.3.6 of 

appendix F to part 75 (scf CO2/mmBtu).
165

HHV = High heat value of the fossil fuel, from fuel 

sampling and analysis (annual average value in 

Btu/lb for solid fuel, Btu/gal for liquid fuel and 

Btu/scf for gaseous fuel, sampled as specified 

(e.g., monthly, quarterly, semi-annually, or by 

lot) in §98.34(a)(2)). The average HHV shall be 

calculated according to the requirements of 

paragraph (a)(2)(ii) of this section.

106 = Conversion factor, Btu per mmBtu.

(iv) Subtract Vff from Vtotal to obtain Vbio, the annual 

volume of CO2 from the combustion of biomass. 

(v) Calculate the biogenic percentage of the annual 

CO2 emissions,expressed as a decimal fraction, using 

Equation C-14 of this section:

total

bio

V

V

% Biogenic  (Eq. C-14)

(vi) Calculate the annual biogenic CO2 mass emissions, 

in metric tons, by multiplying the results obtained from 

Equation C-14 of this section by the annual CO2 mass 

emissions in metric tons, as determined:

(A) Under paragraph (a)(4)(vi) of this section, for 

units using the Tier 4 Calculation Methodology.

(B) Under paragraph (a)(5)(iii)(B) of this section, 

for units using the alternative calculation methodology 

specified in paragraph (a)(5)(iii).

(C) From the electronic data report required under 

§75.64 of this chapter, for units in the Acid Rain Program 

and other units using CEMS to monitor and report CO2 mass 
166

emissions according to part 75 of this chapter. However, 

before calculating the annual biogenic CO2 mass emissions, 

multiply the cumulative annual CO2 mass emissions by 0.91 to 

convert from short tons to metric tons. 

(3) You must use the procedures in paragraphs

(e)(3)(i) through (e)(3)(iii) of this section to determine 

the annual biogenic CO2 emissions from the combustion of 

MSW. These procedures also may be used for any unit that 

co-fires biomass and fossil fuels, including units equipped 

with a CO2 CEMS, and units for which optional separate 

reporting of biogenic CO2 emissions from the combustion of 

tires is selected.

(i) Use an applicable CO2 emissions calculation method 

in this section to quantify the total annual CO2 mass 

emissions from the unit.

(ii) Determine the relative proportions of biogenic 

and non-biogenic CO2 emissions in the flue gas on a 

quarterly basis using the method specified in §98.34(d)

(for units that combust MSW as the primary fuel or as the 

only fuel with a biogenic component) or in §98.34(e) (for 

other units, including units that combust tires). 

(iii) Determine the annual biogenic CO2 mass emissions 

from the unit by multiplying the total annual CO2 mass 
167

emissions by the annual average biogenic decimal fraction 

obtained from §98.34(d) or §98.34(e), as applicable.

(4) [Reserved]

(5) If Equation C-1 or Equation C-2a of this section 

is selected to calculate the annual biogenic mass emissions 

for wood, wood waste, or other solid biomass-derived fuel, 

Equation C-15 of this section may be used to quantify 

biogenic fuel consumption, provided that all of the 

required input parameters are accurately quantified. 

Similar equations and calculation methodologies based on 

steam generation and boiler efficiency may be used, 

provided that they are documented in the GHG Monitoring 

Plan required by §98.3(g)(5). 

 

   

    bio bio

nb

p HHV Eff

H S HI Fuel

2000

* 



(Eq. C-15)

Where:

(Fuel)p = Quantity of biomass consumed during the 

measurement period “p” (tons/year or 

tons/month, as applicable).

H = Average enthalpy of the boiler steam for the 

measurement period (Btu/lb).

S = Total boiler steam production for the 

measurement period (lb/month or lb/year, as 

applicable).

(HI)nb = Heat input from co-fired fossil fuels and 

non-biomass-derived fuels for the 

measurement period, based on company records 

of fuel usage and default or measured HHV 
168

values (Btu/month or Btu/year, as 

applicable).

(HHV)bio = Default or measured high heat value of the 

biomass fuel (Btu/lb).

(Eff)bio = Percent efficiency of biomass-to-energy 

conversion, expressed as a decimal fraction.

2000 = Conversion factor (lb/ton).

§98.34 Monitoring and QA/QC requirements.

The CO2 mass emissions data for stationary fuel 

combustion sources shall be monitored as follows: 

(a) For the Tier 2 Calculation Methodology:

(1) All fuel samples shall be taken at a location in 

the fuel handling system that provides a sample 

representative of the fuel combusted. The fuel sampling 

and analysis may be performed by either the owner or 

operator or the supplier of the fuel. 

(2) The minimum required frequency of the HHV 

sampling and analysis for each type of fuel or fuel mixture 

(blend) is specified in this paragraph. When the specified 

frequency for a particular fuel or blend is based on a 

specified time period (e.g., week, month, quarter, or halfyear), fuel sampling and analysis is required only for 

those time periods in which the fuel or blend is combusted. 

The owner or operator may perform fuel sampling and 

analysis more often than the minimum required frequency, in 

order to obtain a more representative annual average HHV. 
169

(i) For natural gas, semiannual sampling and analysis 

is required (i.e., twice in a calendar year, with 

consecutive samples taken at least four months apart).

(ii) For coal and fuel oil, and for any other solid 

or liquid fuel that is delivered in lots, analysis of at 

least one representative sample from each fuel lot is 

required. For fuel oil, as an alternative to sampling each 

fuel lot, a sample may be taken upon each addition of oil 

to the unit’s storage tank. Flow proportional sampling, 

continuous drip sampling, or daily manual oil sampling may 

also be used, in lieu of sampling each fuel lot. For the 

purposes of this section, a fuel lot is defined as either: 

(A) A shipment or delivery of a single fuel (e.g., 

ship load, barge load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a tank farm, etc.); or

(B) If multiple deliveries of a particular type of 

fuel are received from the same supply source in a given 

calendar month, the deliveries for that month are 

considered, collectively, to comprise a fuel lot, requiring 

only one representative sample. 

(iii) For liquid fuels other than fuel oil, and for 

gaseous fuels other than natural gas (including biogas),

sampling and analysis is required at least once per 
170

calendar quarter. To the extent practicable, consecutive 

quarterly samples shall be taken at least 30 days apart.

(iv) For other solid fuels (except MSW), weekly 

sampling is required to obtain composite samples, which are 

then analyzed monthly.

(v) For fuel blends that are received already mixed, 

as described in paragraph (a)(3)(ii) of this section, 

determine the HHV of the blend as follows. For blends of 

solid fuels (except MSW), weekly sampling is required to 

obtain composite samples, which are analyzed monthly. For 

blends of liquid or gaseous fuels, sampling and analysis is 

required at least once per calendar quarter. More frequent 

sampling is recommended if the composition of the blend 

varies significantly during the year. 

(3) Special Considerations for Blending of Fuels. In 

situations where different types of fuel listed in Table C1 of this subpart (for example, different ranks of coal or 

different grades of fuel oil) are in the same state of 

matter (i.e., solid, liquid, or gas), and are blended prior 

to combustion, use the following procedures to determine 

the appropriate CO2 emission factor and HHV for the blend. 

(i) If the fuels to be blended are received 

separately, and if the quantity (mass or volume) of each 

fuel is measured before the fuels are mixed and combusted, 
171

then, for each component of the blend, calculate the CO2

mass emissions separately. Substitute into Equation C-2a 

of this subpart the total measured mass or volume of the 

component fuel (from company records), together with the 

appropriate default CO2 emission factor from Table C-1, and 

the annual average HHV, calculated according to 

§98.33(a)(2)(ii). In this case, the fact that the fuels 

are blended prior to combustion is of no consequence.

(ii) If the fuel is received as a blend (i.e., 

already mixed), a reasonable estimate of the relative 

proportions of the components of the blend must be made, 

using the best available information (e.g., the approximate 

annual average mass or volume percentage of each fuel, 

based on the typical or expected range of values). 

Determine the appropriate CO2 emission factor and HHV for 

use in Equation C-2a of this subpart, as follows:

(A) Consider the blend to be the “fuel type,” measure 

its HHV at the frequency prescribed in paragraph (a)(2)(v) 

of this section, and determine the annual average HHV value 

for the blend according to §98.33(a)(2)(ii). 

(B) Calculate a heat-weighted CO2 emission factor, 

(EF)B, for the blend, using Equation C-16 of this section. 

The heat-weighting in Equation C-16 is provided by the 
172

default HHVs (from Table C-1) and the estimated mass or 

volume percentages of the components of the blend. 

(C) Substitute into Equation C-2a of this subpart, 

the annual average HHV for the blend (from paragraph 

(a)(3)(ii)(A) of this section) and the calculated value of 

(EF)B, along with the total mass or volume of the blend

combusted during the reporting year, to determine the 

annual CO2 mass emissions from combustion of the blend. 

   

B

n

i

i i i

B HHV

HHV Fuel EF

EF

( )

( ) % ( )

( )

1

 

(Eq. C-16)

Where:

(EF)B = Heat-weighted CO2 emission factor for the blend 

(kg CO2/mmBtu)

(HHV)I = Default high heat value for fuel “i” in the 

blend, from Table C-1 (mmBtu per mass or 

volume)

(%Fuel)I = Estimated mass or volume percentage of fuel “i” 

(mass % or volume %, as applicable, expressed 

as a decimal fraction; e.g., 25% = 0.25) 

(EF)I = Default CO2 emission factor for fuel “i” from 

Table C-1 (mmBtu per mass or volume)

(HHV)B = Annual average high heat value for the blend, 

calculated according to §98.33(a)(2)(ii) (mmBtu 

per mass or volume) 

(iii) Note that for the case described in paragraph 

(a)(3)(ii) of this section, if measured HHV values for the 

individual fuels in the blend or for the blend itself are 
173

not routinely received at the minimum frequency prescribed 

in paragraph (a)(2) of this section (or at a greater 

frequency), and if the unit qualifies to use Tier 1, 

calculate (HHV)B

*, the heat-weighted default HHV for the 

blend, using Equation C-17 of this section. Then, use 

Equation C-16 of this section, replacing the term (HHV)B

with (HHV)B

* in the denominator, to determine the heatweighted CO2 emission factor for the blend. Finally, 

substitute into Equation C-1 of this subpart, the 

calculated values of (HHV)B

* and (EF)B, along with the total 

mass or volume of the blend combusted during the reporting 

year, to determine the annual CO2 mass emissions from 

combustion of the blend. 

   





n

i

HHVB HHV i Fuel i

1

*

( ) %

(Eq. C-17)

Where:

(HHV)B

* = Heat-weighted default high heat value for the 

blend (mmBtu per mass or Volume)

(HHV)I = Default high heat value for fuel “i” in the 

blend, from Table C-1 (mmBtu per mass or 

volume)

(%Fuel)I = Estimated mass or volume percentage of fuel “i” 

in the blend (mass % or volume %, as 

applicable, expressed as a decimal fraction)

(iv) If the fuel blend described in paragraph 

(a)(3)(ii) of this section consists of a mixture of fuel(s) 

listed in Table C-1 of this subpart and one or more fuels 
174

not listed in Table C-1, calculate CO2 and other GHG 

emissions only for the Table C-1 fuel(s), using the best 

available estimate of the mass or volume percentage(s) of 

the Table C-1 fuel(s) in the blend. In this case, Tier 1 

shall be used, with the following modifications to 

Equations C-17 and C-1, to account for the fact that not 

all of the fuels in the blend are listed in Table C-1:

(A) In Equation C-17, apply the term (Fuel)i only to 

the Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will 

be the estimated mass or volume percentage of the fuel in 

the blend, divided by the sum of the mass or volume 

percentages of the Table C-1 fuels. For example, suppose 

that a blend consists of two Table C-1 fuels (“A” and “B”) 

and one fuel type (“C”) not listed in the Table, and that 

the volume percentages of fuels A, B, and C in the blend, 

expressed as decimal fractions, are, respectively, 0.50, 

0.30, and 0.20. The term (Fuel)i in Equation C-17 for fuel 

A will be 0.50/(0.50 + 0.30) = 0.625, and for fuel B, 

(Fuel)i will be 0.30/(0.50 + 0.30) = 0.375.

(B) In Equation C-1, the term “Fuel” will be equal to 

the total mass or volume of the blended fuel combusted 

during the year multiplied by the sum of the mass or volume 

percentages of the Table C-1 fuels in the blend. For the 
175

example in paragraph (a)(3)(iv)(A) of this section, 

“Fuel” = (Annual volume of the blend combusted)(0.80).

(4) If, for a particular type of fuel, HHV sampling 

and analysis is performed more often than the minimum 

frequency specified in paragraphs (a)(2)of this section, 

the results of all valid fuel analyses shall be used in the 

GHG emission calculations. 

(5) If, for a particular type of fuel, valid HHV 

values are obtained at less than the minimum frequency 

specifed in paragraphs (a)(2) of this section, appropriate 

substitute data values shall be used in the emissions 

calculations, in accordance with missing data procedures of 

§98.35.

(6) You must use one of the following appropriate 

fuel sampling and analysis methods. You may use a method

published by a consensus standards organization if such a 

method exists, or you may use industry consensus standard 

practice to determine the high heat values. Consensusbased standards organizations include, but are not limited 

to, the following: ASTM International, the American 

National Standards Institute (ANSI), the American Gas 

Association (AGA), the American Society of Mechanical 

Engineers (ASME), the American Petroleum Institute (API), 

and the North American Energy Standards Board (NAESB). 
176

Alternatively, for gaseous fuels, the HHV may be calculated 

using chromatographic analysis together with standard 

heating values of the fuel constituents, provided that the 

gas chromatograph is operated, maintained, and calibrated 

according to the manufacturer’s instructions. The 

method(s) used shall be documented in the Monitoring Plan 

required under §98.3(g)(5). 

(b) For the Tier 3 Calculation Methodology:

(1) You must calibrate each oil and gas flow meter 

according to §98.3(i) and the provisions of this paragraph 

(b)(1).

(i) Perform calibrations using any of the test 

methods and procedures in this paragraph (b)(1)(i). The 

method(s) used shall be documented in the Monitoring Plan 

required under §98.3(g)(5).

(A) You may use an appropriate flow meter calibration

method published by a consensus standards organization, if 

such a method exists. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB).
177

(B) You may use the calibration procedures specified 

by the flow meter manufacturer.

(C) You may use an industry-accepted or industry 

consensus standard calibration practice.

(ii) In addition to the initial calibration required 

by §98.3(i), recalibrate each fuel flow meter (except as 

otherwise provided in paragraph (b)(1)(iii) of this 

section) either annually, at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by industry consensus standard practice.

(iii) Fuel billing meters are exempted from the 

initial and ongoing calibration requirements of this 

paragraph and from the Monitoring Plan and recordkeeping 

requirements of §98.3(g)(5)(i)(C) and (g)(7), provided that 

the fuel supplier and the unit combusting the fuel do not 

have any common owners and are not owned by subsidiaries or 

affiliates of the same company. Meters used exclusively to 

measure the flow rates of fuels that are only used for unit 

startup or ignition are also exempted from the initial and 

ongoing calibration requirements of this paragraph.

(iv) For the initial calibration of an orifice, 

nozzle, or venturi meter; in-situ calibration of the 

transmitters is sufficient. A primary element inspection 

(PEI) shall be performed at least once every three years. 
178

(v) For the continuously-operating units and 

processes described in §98.3(i)(6), the required flow meter 

recalibrations and, if necessary, the PEIs may be postponed 

until the next scheduled maintenance outage.

(vi) If a mixture of liquid or gaseous fuels is 

transported by a common pipe, you may either separately 

meter each of the fuels prior to mixing, using flow meters 

calibrated according to §98.3(i), or consider the fuel 

mixture to be the “fuel type” and meter the mixed fuel, 

using a flow meter calibrated according to §98.3(i).

(2) Oil tank drop measurements (if used to determine 

liquid fuel use volume) shall be performed according to any 

an appropriate method published by a consensus-based 

standards organization (e.g., the American Petroleum 

Institute).

(3) The carbon content and, if applicable, molecular 

weight of the fuels shall be determined according to the 

procedures in paragraph (b)(3). 

(i) All fuel samples shall be taken at a location in 

the fuel handling system that provides a sample 

representative of the fuel combusted. The fuel sampling 

and analysis may be performed by either the owner or 

operator or by the supplier of the fuel. 
179

(ii) For each type of fuel, the minimum required 

frequency for collecting and analyzing samples for carbon 

content and (if applicable) molecular weight is specified 

in this paragraph. When the sampling frequency is based on 

a specified time period (e.g., week, month, quarter, or 

half-year), fuel sampling and analysis is required for only 

those time periods in which the fuel is combusted. 

(A) For natural gas, semiannual sampling and analysis 

is required (i.e., twice in a calendar year, with 

consecutive samples taken at least four months apart).

(B) For coal and fuel oil and for any other solid or 

liquid fuel that is delivered in lots, analysis of at least 

one representative sample from each fuel lot is required. 

For fuel oil, as an alternative to sampling each fuel lot, 

a sample may be taken upn each addition of oil to the 

storage tank. Flow proportional sampling, continuous drip 

sampling, or daily manual oil sampling may also be used, in 

lieu of sampling each fuel lot. For the purposes of this 

section, a fuel lot is defined as either of the following: 

(1) A shipment or delivery of a single fuel (e.g., 

ship load, barge load, group of trucks, group of railroad 

cars, oil delivery via pipeline from a tank farm, etc.).

(2) If multiple deliveries of a particular type of 

fuel are received from the same supply source in a given 
180

calendar month, the deliveries for that month are 

considered, collectively, to comprise a fuel lot, requiring 

only one representative sample. 

(C) For liquid fuels other than fuel oil and for 

biogas; sampling and analysis is required at least once per 

calendar quarter. To the extent practicable, consecutive 

quarterly samples shall be taken at least 30 days apart.

(D) For other solid fuels (except MSW), weekly 

sampling is required to obtain composite samples, which are 

then analyzed monthly. 

(E) For gaseous fuels other than natural gas and 

biogas (e.g., process gas), daily sampling and analysis to 

determine the carbon content and molecular weight of the 

fuel is required if continuous, on-line equipment, such as 

a gas chromatograph, is in place to make these 

measurements. Otherwise, weekly sampling and analysis 

shall be performed. 

(F) For mixtures (blends) of solid fuels, weekly 

sampling is required to obtain composite samples, which are 

analyzed monthly. For blends of liquid fuels, and for gas 

mixtures consisting only of natural gas and biogas, 

sampling and analysis is required at least once per 

calendar quarter. For gas mixtures that contain gases 

other than natural gas (including biogas), daily sampling 
181

and analysis to determine the carbon content and molecular 

weight of the fuel is required if continuous, on-line 

equipment is in place to make these measurements. 

Otherwise, weekly sampling and analysis shall be performed.

(iii) If, for a particular type of fuel, sampling and 

analysis for carbon content and molecular weight is 

performed more often than the minimum frequency specified 

in paragraph (b)(3) of this section, the results of all 

valid fuel analyses shall be used in the GHG emission 

calculations. 

(iv) If, for a particular type of fuel, sampling and 

analysis for carbon content and molecular weight is 

performed at less than the minimum frequency specifed in 

paragraph (b)(3) of this section, appropriate substitute 

data values shall be used in the emissions calculations, in 

accordance with the missing data procedures of §98.35.

(v) To calculate the CO2 mass emissions from 

combustion of a blend of fuels in the same state of matter 

(solid, liquid, or gas), you may either:

(A) Apply Equation C-3, C-4 or C-5 of this subpart 

(as applicable) to each component of the blend, if the mass 

or volume, the carbon content, and (if applicable), the 

molecular weight of each component are accurately measured 

prior to blending; or 
182

(B) Consider the blend to be the “fuel type”. Then, 

at the frequency specified in paragraph (b)(3)(ii)(F) of 

this section, measure the carbon content and, if 

applicable, the molecular weight of the blend and calculate 

the annual average value of each parameter in the manner 

described in §98.33(a)(2)(ii). Also measure the mass or 

volume of the blended fuel combusted during the reporting 

year. Substitute these measured values into Equation C-3, 

C-4, or C-5 of this subpart (as applicable).

(4) You must use one of the following appropriate 

fuel sampling and analysis methods. You may use a method 

published by a consensus standards organization if such a 

method exists, or you may use industry consensus standard 

practice to determine the carbon content and molecular 

weight (for gaseous fuel) of the fuel. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). Alternatively, 

the results of chromatographic analysis of the fuel may be 

used, provided that the gas chromatograph is operated, 

maintained, and calibrated according to the manufacturer’s 
183

instructions. The method(s) used shall be documented in 

the Monitoring Plan required under §98.3(g)(5).

(c) For the Tier 4 Calculation Methodology, the CO2,

flow rate, and (if applicable) moisture monitors must be 

certified prior to the applicable deadline specified in 

§98.33(b)(5). 

(1) For initial certification, you may use any one of 

the following three procedures in this paragraph.

(i) Sections 75.20(c)(2), (c)(4), and (c)(5) though 

(c)(7) of this chapter and appendix A to part 75 of this 

chapter.

(ii) The calibration drift test and relative accuracy 

test audit (RATA) procedures of Performance Specification 3 

in appendix B to part 60 of this chapter (for the CO2

concentration monitor) and Performance Specification 6 in 

appendix B to part 60 of this chapter (for the continuous 

emission rate monitoring system (CERMS)). 

(iii) The provisions of an applicable State 

continuous monitoring program.

(2) If an O2 concentration monitor is used to 

determine CO2 concentrations, the applicable provisions of 

part 75 of this chapter, part 60 of this chapter, or an 

applicable State continuous monitoring program shall be 

followed for initial certification and on-going quality 
184

assurance, and all required RATAs of the monitor shall be 

done on a percent CO2 basis. 

(3) For ongoing quality assurance, follow the 

applicable procedures in either appendix B to part 75 of 

this chapter, appendix F to part 60 of this chapter, or an 

applicable State continuous monitoring program. If 

appendix F to part 60 of this chapter is selected for ongoing quality assurance, perform daily calibration drift 

assessments for both the CO2 monitor (or surrogate O2

monitor) and the flow rate monitor, conduct cylinder gas 

audits of the CO2 concentration monitor in three of the four 

quarters of each year (except for non-operating quarters), 

and perform annual RATAs of the CO2 concentration monitor 

and the CERMS. 

(4) For the purposes of this part, the stack gas 

volumetric flow rate monitor RATAs required by appendix B 

to part 75 of this chapter and the annual RATAs of the 

CERMS required by appendix F to part 60 of this chapter 

need only be done at one operating level, representing 

normal load or normal process operating conditions, both 

for initial certification and for ongoing quality 

assurance.

(5) If, for any source operating hour, quality 

assured data are not obtained with a CO2 monitor (or 
185

surrogate O2 monitor), flow rate monitor, or (if applicable) 

moisture monitor, use appropriate substitute data values 

in accordance with the missing data provisions of §98.35.

(6) For certain applications where combined process 

emissions and combustion emissions are measured, the CO2

concentrations in the flue gas may be considerably higher 

than for combustion emissions alone. In such cases, the 

span of the CO2 monitor may, if necessary, be set higher 

than the specified levels in the applicable regulations. 

If the CO2 span value is set higher than 20 percent CO2, the 

cylinder gas audits of the CO2 monitor under appendix F to 

part 60 of this chapter may be performed at 40 to 60 

percent and 80 to 100 percent of span, in lieu of the 

prescribed calibration levels of 5 to 8 percent CO2 and 10

to 14 percent CO2. 

(7) Hourly average data from the CEMS shall be 

validated in a manner consistent with one of the following: 

§§60.13(h)(2)(i) through (h)(2)(vi) of this chapter; 

§75.10(d)(1) of this chapter; or the hourly data validation 

requirements of an applicable State CEM regulation. 

(d) When municipal solid waste (MSW) is either the 

primary fuel combusted in a unit or the only fuel with a 

biogenic component combusted in the unit, determine the 

biogenic portion of the CO2 emissions using ASTM D6866-08 
186

Standard Test Methods for Determining the Biobased Content 

of Solid, Liquid, and Gaseous Samples Using Radiocarbon 

Analysis (incorporated by reference, see §98.7) and ASTM 

D7459-08 Standard Practice for Collection of Integrated 

Samples for the Speciation of Biomass (Biogenic) and 

Fossil-Derived Carbon Dioxide Emitted from Stationary 

Emissions Sources (incorporated by reference, see §98.7). 

Perform the ASTM D7459-08 sampling and the ASTM D6866-08 

analysis at least once in every calendar quarter in which 

MSW is combusted in the unit. Collect each gas sample 

during normal unit operating conditions for at least 24 

consecutive hours or for as long as is deemed necessary to 

obtain a representative sample. One suggested alternative 

sampling approach would be to collect an integrated sample 

by extracting a small amount of flue gas (e.g., 1 to 5 cc) 

in each unit operating hour during the quarter. Separate 

the total annual CO2 emissions into the biogenic and nonbiogenic fractions using the average proportion of biogenic 

emissions of all samples analyzed during the reporting 

year. Express the results as a decimal fraction (e.g., 

0.30, if 30 percent of the CO2 is biogenic). When MSW is 

the primary fuel for multiple units at the facility, and 

the units are fed from a common fuel source, testing at 

only one of the units is sufficient.
187

(e) For other units that combust combinations of 

biomass fuel(s) (or heterogeneous fuels that have a biomass 

component, e.g., tires) and fossil (or other non-biogenic)

fuel(s), in any proportions, ASTM D6866-08 and ASTM D7459-

08 may be used to determine the biogenic portion of the CO2

emissions. Perform the ASTM D7459-08 sampling and the ASTM 

D6866-08 analysis in every calendar quarter in which 

biomass and non-biogenic fuels are co-fired in the unit. 

Collect each gas sample using ASTM D7459-08 during normal 

unit operation for at least 24 consecutive hours or for as 

long as is necessary to obtain a representative sample. If 

the types of fuels combusted in the unit and their relative 

proportions are not consistent throughout the quarter, more 

frequent, periodic sampling of the flue gas should be 

considered. For example, an integrated sample could be 

collected by extracting a small amount of the flue gas 

(e.g., 1 to 5 cc) in each unit operating hour of the 

quarter. If the primary fuel for multiple units at the 

facility consists of tires, and the units are fed from a 

common fuel source, testing at only one of the units is 

sufficient. 

(f) The records required under §98.3(g)(2)(i) shall 

include an explanation of how the following parameters are 
188

determined from company records (or, if applicable, from 

the best available information):

(1) Fuel consumption, when the Tier 1 and Tier 2 

Calculation Methodologies are used, including cases where

§98.36(c)(4) applies.

(2) Fuel consumption, when solid fuel is combusted 

and the Tier 3 Calculation Methodology is used. 

(3) Fossil fuel consumption when §98.33(e)(2) applies 

to a unit that uses CEMS to quantify CO2 emissions and that 

combusts both fossil and biomass fuels.

(4) Sorbent usage, when §98.33(d) applies. 

(5) Quantity of steam generated by a unit when 

§98.33(a)(2)(iii) applies.

(6) Biogenic fuel consumption under §98.33(e)(5).

(7) Fuel usage for CH4 and N2O emissions calculations 

under §98.33(c)(4)(ii).

(8) Mass of biomass combusted, for premixed fuels 

that contain biomass and fossil fuels under 

§98.33(e)(1)(iii). 

§98.35 Procedures for estimating missing data. 

Whenever a quality-assured value of a required 

parameter is unavailable (e.g., if a CEMS malfunctions 

during unit operation or if a required fuel sample is not 
189

taken), a substitute data value for the missing parameter 

shall be used in the calculations. 

(a) For all units subject to the requirements of the 

Acid Rain Program, and all other stationary combustion 

units subject to the requirements of this part that monitor 

and report emissions and heat input data in accordance with 

part 75 of this chapter, the missing data substitution 

procedures in part 75 of this chapter shall be followed for 

CO2 concentration, stack gas flow rate, fuel flow rate, high 

heating value, and fuel carbon content. 

(b) For units that use the Tier 1, Tier 2, Tier 3, 

and Tier 4 Calculation Methodologies, perform missing data 

substitution as follows for each parameter: 

(1) For each missing value of the high heating value, 

carbon content, or molecular weight of the fuel, substitute 

the arithmetic average of the quality-assured values of 

that parameter immediately preceding and immediately 

following the missing data incident. If the “after” value 

has not been obtained by the time that the GHG emissions 

report is due, you may use the “before” value for missing 

data substitution or the best available estimate of the 

parameter, based on all available process data (e.g., 

electrical load, steam production, operating hours). If, 

for a particular parameter, no quality-assured data are 
190

available prior to the missing data incident, the 

substitute data value shall be the first quality-assured 

value obtained after the missing data period. 

(2) For missing records of CO2 concentration, stack 

gas flow rate, percent moisture, fuel usage, and sorbent 

usage, the substitute data value shall be the best 

available estimate of the parameter, based on all available 

process data (e.g., electrical load, steam production, 

operating hours, etc.). You must document and retain 

records of the procedures used for all such estimates.

§98.36 Data reporting requirements. 

(a) In addition to the facility-level information 

required under §98.3, the annual GHG emissions report shall 

contain the unit-level or process-level emissions data in 

paragraphs (b) through (d) of this section (as applicable) 

and the emissions verification data in paragraph (e) of 

this section.

(b) Units that use the four tiers. You shall report 

the following information for stationary combustion units 

that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology 

in §98.33(a) to calculate CO2 emissions, except as otherwise 

provided in paragraphs (c) and (d) of this section:

(1) The unit ID number.

(2) A code representing the type of unit.
191

(3) Maximum rated heat input capacity of the unit, in 

mmBtu/hr for boilers and process heaters only and relevant 

units of measure for other combustion sources.

(4) Each type of fuel combusted in the unit during 

the report year.

(5) The methodology (i.e., tier) used to calculate 

the CO2 emissions for each type of fuel combusted (i.e., 

Tier 1, 2, 3, or 4).

(6) The methodology start date, for each fuel type.

(7) The methodology end date, for each fuel type.

(8) For a unit that uses Tiers 1, 2, or 3:

(i) The annual CO2 mass emissions (including biogenic 

CO2), and the annual CH4, and N2O mass emissions for each 

type of fuel combusted during the reporting year, expressed 

in metric tons of each gas and in metric tons of CO2e; and

(ii) Metric tons of biogenic CO2 emissions (if 

applicable).

(9) For a unit that uses Tier 4:

(i) If the total annual CO2 mass emissions measured by 

the CEMS consists entirely of non-biogenic CO2 (i.e., CO2

from fossil fuel combustion plus, if applicable, CO2 from 

sorbent and/or process CO2), report the total annual CO2

mass emissions, expressed in metric tons. You are not 
192

required to report the combustion CO2 emissions by fuel 

type. 

(ii) If the total annual CO2 mass emissions measured 

by the CEMS includes both biogenic and non-biogenic CO2, 

separately report the annual non-biogenic CO2 mass emissions 

and the annual CO2 mass emissions from biomass combustion, 

each expressed in metric tons. You are not required to 

report the combustion CO2 emissions by fuel type. 

(iii) An estimate of the heat input from each type of 

fuel listed in Table C-2 of this subpart that was combusted 

in the unit during the report year, and the annual CH4 and 

N2O emissions for each of these fuels, expressed in metric 

tons of each gas and in metric tons of CO2e. 

(10) Annual CO2 emissions from sorbent (if calculated 

using Equation C-11 of this subpart), expressed in metric 

tons.

(c) Reporting alternatives for units using the four 

Tiers. You may use any of the applicable reporting 

alternatives of this paragraph to simplify the unit-level 

reporting required under paragraph (b) of this section:

(1) Aggregation of units. If a facility contains two 

or more units (e.g., boilers or combustion turbines), each 

of which has a maximum rated heat input capacity of 250 

mmBtu/hr or less, you may report the combined GHG emissions 
193

for the group of units in lieu of reporting GHG emissions 

from the individual units, provided that the use of Tier 4 

is not required or elected for any of the units and the 

units use the same tier for any common fuels combusted. If 

this option is selected, the following information shall be 

reported instead of the information in paragraph (b) of 

this section:

(i) Group ID number, beginning with the prefix “GP”.

(ii) The number of units in the group.

(iii) Cumulative maximum rated heat input capacity of 

the group (mmBtu/hr).

(iv) The highest maximum rated heat input capacity of 

any unit in the group (mmBtu/hr).

(v) Each type of fuel combusted in the group of units 

during the reporting year.

(vi) Annual CO2 mass emissions and annual CH4, and N2O 

mass emissions aggregated for each type of fuel combusted 

in the group of units during the report year, expressed in 

metric tons of each gas and in metric tons of CO2e. If any 

of the units burn both fossil fuels and biomass, report 

also the annual CO2 emissions from combustion of all fossil 

fuels combined and annual CO2 emissions from combustion of 

all biomass fuels combined, expressed in metric tons.
194

(vii) The methodology (i.e., tier) used to calculate 

the CO2 mass emissions for each type of fuel combusted in 

the units (i.e., Tier 1, Tier 2, or Tier 3).

(viii) The methodology start date, for each fuel 

type.

(ix) The methodology end date, for each fuel type.

(x) The calculated CO2 mass emissions (if any) from 

sorbent expressed in metric tons.

(2) Monitored common stack or duct configurations. 

When the flue gases from two or more stationary fuel 

combustion units at a facility are combined together in a 

common stack or duct before exiting to the atmosphere and 

if CEMS are used to continuously monitor CO2 mass emissions 

at the common stack or duct according to the Tier 4 

Calculation Methodology, you may report the combined 

emissions from the units sharing the common stack or duct, 

in lieu of separately reporting the GHG emissions from the 

individual units. This monitoring and reporting 

alternative may also be used when process off-gases or a 

mixture of combustion products and process gases are 

combined together in a common stack or duct before exiting 

to the atmosphere. Whenever the common stack or duct 

monitoring option is applied, the following information 
195

shall be reported instead of the information in paragraph 

(b) of this section:

(i) Common stack or duct identification number, 

beginning with the prefix “CS”.

(ii) Number of units sharing the common stack or 

duct. Report “1” when the flue gas flowing through the 

common stack or duct includes both combustion products and 

process off-gases, and all of the effluent comes from a 

single unit (e.g., a furnace, kiln, or smelter).

(iii) Combined maximum rated heat input capacity of 

the units sharing the common stack or duct (mmBtu/hr). 

This data element is required only when all of the units 

sharing the common stack are stationary fuel combustion 

units.

(iv) Each type of fuel combusted in the units during 

the year.

(v) The methodology (tier) used to calculate the CO2

mass emissions, i.e., Tier 4.

(vi) The methodology start date.

(vii) The methodology end date.

(viii) Total annual CO2 mass emissions measured by the 

CEMS, expressed in metric tons. If any of the units burn 

both fossil fuels and biomass, separately report the annual 

non-biogenic CO2 mass emissions (i.e., CO2 from fossil fuel 
196

combustion plus, if applicable, CO2 from sorbent and/or 

process CO2) and the annual CO2 mass emissions from biomass 

combustion, each expressed in metric tons.

(ix) An estimate of the heat input from each type of 

fuel listed in Table C-2 of this subpart that was combusted 

during the report year in the units sharing the common 

stack or duct during the report year, and, for each of 

these fuels, the annual CH4 and N2O mass emissions from the 

units sharing the common stack or duct, expressed in metric 

tons of each gas and in metric tons of CO2e.

(3) Common pipe configurations. When two or more 

liquid-fired or gaseous-fired stationary combustion units 

at a facility combust the same type of fuel and the fuel is 

fed to the individual units through a common supply line or 

pipe, you may report the combined emissions from the units 

served by the common supply line, in lieu of separately 

reporting the GHG emissions from the individual units, 

provided that the total amount of fuel combusted by the 

units is accurately measured at the common pipe or supply 

line using a fuel flow meter. For Tier 3 applications, the 

flow meter shall be calibrated in accordance with

§98.34(b). If a portion of the fuel measured at the main 

supply line is diverted to either: a flare; or another 

stationary fuel combustion unit (or units), including units 
197

that use a CO2 mass emissions calculation method in part 75 

of this chapter; or a chemical or industrial process (where 

it is used as a raw material but not combusted), and the 

remainder of the fuel is distributed to a group of 

combustion units for which you elect to use the common pipe 

reporting option, you may use company records to subtract 

out the diverted portion of the fuel from the fuel measured 

at the main supply line prior to performing the GHG 

emissions calculations for the group of units using the 

common pipe option. If the diverted portion of the fuel is 

combusted, the GHG emissions from the diverted portion 

shall be accounted for in accordance with the applicable 

provisions of this part. When the common pipe option is 

selected, the applicable tier shall be used based on the 

maximum rated heat input capacity of the largest unit 

served by the common pipe configuration, except where the 

applicable tier is based on criteria other than unit size. 

For example, if the maximum rated heat input capacity of 

the largest unit is greater than 250 mmBtu/hr, Tier 3 will 

apply, unless the fuel transported through the common pipe 

is natural gas or distillate oil, in which case Tier 2 may 

be used, in accordance with §98.33(b)(2)(ii). As a second 

example, in accordance with §98.33(b)(1)(v), Tier 1 may be 

used regardless of unit size when natural gas is 
198

transported through the common pipe, if the annual fuel 

consumption is obtained from gas billing records in units 

of therms. When the common pipe reporting option is 

selected, the following information shall be reported 

instead of the information in paragraph (b) of this 

section:

(i) Common pipe identification number, beginning with 

the prefix “CP”.

(ii) The number of units served by the common pipe.

(iii) The highest maximum rated heat input capacity 

of any unit served by the common pipe (mmBtu/hr).

(iv) The fuels combusted in the units during the 

reporting year.

(v) The methodology used to calculate the CO2 mass 

emissions (i.e., Tier 1, Tier 2, or Tier 3).

(vi) If the any of the units burns both fossil fuels 

and biomass, the annual CO2 mass emissions from combustion 

of all fossil fuels and annual CO2 emissions from combustion 

of all biomass fuels from the units served by the common 

pipe, expressed in metric tons.

(vii) Annual CO2 mass emissions and annual CH4 and N2O 

emissions from each fuel type for the units served by the 

common pipe, expressed in metric tons of each gas and in 

metric tons of CO2e.
199

(viii) Methodology start date

(ix) Methodology end date

(4) The following alternative reporting option 

applies to situations where a common liquid or gaseous fuel 

supply is shared between one or more large combustion 

units, such as boilers or combustion turbines (including 

units subject to subpart D of this part); and small 

combustion sources on-site, including but not limited to

space heaters and hot water heaters. In this case, you may 

simplify reporting by attributing all of the GHG emissions 

from combustion of the shared fuel to the large combustion 

unit(s), provided that:

(i) The total quantity of the fuel combusted during 

the report year in the units sharing the fuel supply is 

measured, either at the “gate” to the facility or at a 

point inside the facility, using a fuel flow meter, billing 

meter, or tank drop measurements (as applicable);

(ii) On an annual basis, at least 95 percent (by mass 

or volume) of the shared fuel is combusted in the large 

combustion unit(s), and the remainder is combusted in the 

small combustion sources. Company records may be used to 

determine the percentage distribution of the shared fuel to 

the large and small units; and
200

(iii) The use of this reporting option is documented 

in the Monitoring Plan required under §98.3(g)(5). 

Indicate in the Monitoring Plan which units share the 

common fuel supply and the method used to demonstrate that 

this alternative reporting option applies. For the small 

combustion sources on-site, a description of the types of 

units and the approximate number of units is sufficient.

(d) Units subject to part 75 of this chapter. 

(1) For stationary combustion units that are subject 

to subpart D of this part, you shall report the following 

unit-level information: 

(i) Unit or stack identification numbers. Use exact 

same unit, common stack, common pipe, or multiple stack 

identification numbers that represent the monitored 

locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are 

reported under §75.64 of this chapter. 

(ii) Annual CO2 emissions at each monitored location, 

expressed in both short tons and metric tons. Reporting of 

biogenic CO2 emissions under §98.3(c)(4)(ii) and 

§98.3(c)(4)(iii)(A) is optional. Subpart D units are not 

required to report biogenic CO2 emissions under 

§§98.3(c)(4)(ii) and (c)(4)(iii)(A).

(iii) Annual CH4 and N2O emissions at each monitored 

location, for each fuel type listed in Table C-2 that was 
201

combusted during the year (except as otherwise provided in 

§98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e. 

(iv) The total heat input from each fuel listed in 

Table C-2 that was combusted during the year (except as 

otherwise provided in §98.33(c)(4)(ii)(B)), expressed in 

mmBtu. 

(v) Identification of the Part 75 methodology used to 

determine the CO2 mass emissions.

(vi) Methodology start date. 

(vii) Methodology end date. 

(viii) Acid Rain Program indicator.

(ix) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons of CO2e (optional). 

(2) For units that use the alternative CO2 mass 

emissions calculation methods provided in §98.33(a)(5), you 

shall report the following unit-level information:

(i) Unit, stack, or pipe ID numbers. Use exact same 

unit, common stack, common pipe, or multiple stack 

identification numbers that represent the monitored 

locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are 

reported under §75.64 of this chapter. 

(ii) For units that use the alternative methods 

specified in §98.33(a)(5)(i) and (ii) to monitor and report 
202

heat input data year-round according to appendix D to part 

75 of this chapter or §75.19 of this chapter:

(A) Each type of fuel combusted in the unit during 

the reporting year.

(B) The methodology used to calculate the CO2 mass 

emissions for each fuel type. 

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate whether heat input is 

calculated according to appendix D to part 75 of this 

chapter or §75.19 of this chapter.

(F) Annual CO2 emissions at each monitored location, 

across all fuel types, expressed in metric tons of CO2e. 

(G) Annual heat input from each type of fuel listed 

in Table C-2 of this subpart that was combusted during the 

reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emisions at each monitored 

location, from each fuel type listed in Table C-2 of this 

subpart that was combusted during the reporting year

(except as otherwise provided in §98.33(c)(4)(ii)(D)), 

expressed in metric tons CO2e.

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2e (optional).
203

(iii) For units with continuous monitoring systems 

that use the alternative method for units with continuous 

monitoring systems in §98.33(a)(5)(iii) to monitor heat 

input year-round according to part 75 of this chapter:

(A) Each type of fuel combusted during the reporting 

year.

(B) Methodology used to calculate the CO2 mass 

emissions.

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate that the heat input 

data is derived from CEMS measurements.

(F) The total annual CO2 emissions at each monitored 

location, expressed in metric tons of CO2e. 

(G) Annual heat input from each type of fuel listed 

in Table C-2 of this subpart that was combusted during the 

reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emisions at each monitored 

location, from each fuel type listed in Table C-2 of this 

subpart that was combusted during the reporting year

(except as otherwise provided in §98.33(c)(4)(ii)(B)), 

expressed in metric tons CO2e.

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2e (optional).
204

(e) Verification data. You must keep on file, in a 

format suitable for inspection and auditing, sufficient 

data to verify the reported GHG emissions. This data and 

information must, where indicated in this paragraph (e), be 

included in the annual GHG emissions report. 

(1) The applicable verification data specified in 

this paragraph (e) are not required to be kept on file or 

reported for units that meet any one of the three following 

conditions:

(i) Are subject to the Acid Rain Program.

(ii) Use the alternative methods for units with 

continuous monitoring systems provided in §98.33(a)(5).

(iii) Are not in the Acid Rain Program, but are 

required to monitor and report CO2 mass emissions and heat 

input data year-round, in accordance with part 75 of this 

chapter. 

(2) For stationary combustion sources using the Tier 

1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in 

§98.33(a) to quantify CO2 emissions, the following 

additional information shall be kept on file and included 

in the GHG emissions report, where indicated: 

(i) For the Tier 1 Calculation Methodology, report 

the total quantity of each type of fuel combusted in the 

unit or group of aggregated units (as applicable) during 
205

the reporting year, in short tons for solid fuels, gallons 

for liquid fuels and standard cubic feet or, if applicable, 

therms for gaseous fuels.

(ii) For the Tier 2 Calculation Methodology, report:

(A) The total quantity of each type of fuel combusted 

in the unit or group of aggregated units (as applicable) 

during each month of the reporting year. Express the 

quantity of each fuel combusted during the measurement

period in short tons for solid fuels, gallons for liquid 

fuels, and scf for gaseous fuels.

(B) The frequency of the HHV determinations (e.g., 

once a month, once per fuel lot).

(C) The high heat values used in the CO2 emissions 

calculations for each type of fuel combusted during the 

reporting year, in mmBtu per short ton for solid fuels, 

mmBtu per gallon for liquid fuels, and mmBtu per scf for 

gaseous fuels. Report a HHV value for each calendar month 

in which HHV determination is required. If multiple values 

are obtained in a given month, report the arithmetic 

average value for the month. Indicate whether each 

reported HHV is a measured value or a substitute data 

value.

(D) If Equation C-2c of this subpart is used to 

calculate CO2 mass emissions, report the total quantity 
206

(i.e., pounds) of steam produced from MSW or solid fuel 

combustion during each month of the reporting year, and the 

ratio of the maximum rate heat input capacity to the design 

rated steam output capacity of the unit, in mmBtu per lb of 

steam. 

(iii) For the Tier 2 Calculation Methodology, keep 

records of the methods used to determine the HHV for each 

type of fuel combusted and the date on which each fuel 

sample was taken, except where fuel sampling data are 

received from the fuel supplier. In that case, keep 

records of the dates on which the results of the fuel 

analyses for HHV are received. 

(iv) For the Tier 3 Calculation Methodology, report: 

(A) The quantity of each type of fuel combusted in 

the unit or group of units (as applicable) during each 

month of the reporting year, in short tons for solid fuels, 

gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of carbon content and, if 

applicable, molecular weight determinations for each type 

of fuel for the reporting year (e.g., daily, weekly, 

monthly, semiannually, once per fuel lot). 

(C) The carbon content and, if applicable, gas 

molecular weight values used in the emission calculations 

(including both valid and substitute data values). For 
207

each calendar month of the reporting year in which carbon 

content and, if applicable, molecular weight determination 

is required, report a value of each parameter. If multiple 

values of a parameter are obtained in a given month, report 

the arithmetic average value for the month. Express carbon 

content as a decimal fraction for solid fuels, kg C per 

gallon for liquid fuels, and kg C per kg of fuel for 

gaseous fuels. Express the gas molecular weights in units 

of kg per kg-mole. 

(D) The total number of valid carbon content 

determinations and, if applicable, molecular weight 

determinations made during the reporting year, for each 

fuel type.

(E) The number of substitute data values used for 

carbon content and, if applicable, molecular weight used in 

the annual GHG emissions calculations.

(F) The annual average HHV, when measured HHV data, 

rather than a default HHV from Table C-1 of this subpart, 

are used to calculate CH4 and N2O emissions for a Tier 3 

unit, in accordance with §98.33(c)(1).

(v) For the Tier 3 Calculation Methodology, keep 

records of the following:
208

(A) For liquid and gaseous fuel combustion, the dates 

and results of the initial calibrations and periodic 

recalibrations of the required fuel flow meters. 

(B) For fuel oil combustion, the method from 

§98.34(b) used to make tank drop measurements (if 

applicable).

(C) The methods used to determine the carbon content 

for each type of fuel combusted. 

(D) The methods used to calibrate the fuel flow 

meters).

(E) The date on which each fuel sample was taken, 

except where fuel sampling data are received from the fuel 

supplier. In that case, keep records of the dates on which 

the results of the fuel analyses for carbon content and (if 

applicable) molecular weight are received.

(vi) For the Tier 4 Calculation Methodology, report:

(A) The total number of source operating hours in the 

reporting year.

(B) The cumulative CO2 mass emissions in each quarter 

of the reporting year, i.e., the sum of the hourly values 

calculated from Equation C-6 or C-7 of this subpart (as 

applicable), in metric tons. 

(C) For CO2 concentration, stack gas flow rate, and 

(if applicable) stack gas moisture content, the percentage 
209

of source operating hours in which a substitute data value 

of each parameter was used in the emissions calculations.

(vii) For the Tier 4 Calculation Methodology, keep 

records of: 

(A) Whether the CEMS certification and quality 

assurance procedures of part 75 of this chapter, part 60 of 

this chapter, or an applicable State continuous monitoring 

program were used. 

(B) The dates and results of the initial 

certification tests of the CEMS. 

(C) The dates and results of the major quality 

assurance tests performed on the CEMS during the reporting 

year, i.e., linearity checks, cylinder gas audits, and 

relative accuracy test audits (RATAs). 

(viii) If CO2 emissions that are generated from acid 

gas scrubbing with sorbent injection are not captured using 

CEMS, report:

(A) The total amount of sorbent used during the 

report year, in short tons. 

(B) The molecular weight of the sorbent.

(C) The ratio (“R”) in Equation C-11 of this subpart.

(ix) For units that combust both fossil fuel and 

biomass, when biogenic CO2 is determined according to 
210

§98.33(e)(2), you shall report the following additional 

information, as applicable:

(A) The annual volume of CO2 emitted from the 

combustion of all fuels, i.e., Vtotal, in scf.

(B) The annual volume of CO2 emitted from the 

combustion of fossil fuels, i.e., Vff, in scf. If more than 

one type of fossil fuel was combusted, report the 

combustion volume of CO2 for each fuel separately as well as 

the total.

(C) The annual volume of CO2 emitted from the 

combustion of biomass, i.e., Vbio, in scf.

(D) The carbon-based F-factor used in Equation C-13 

of this subpart, for each type of fossil fuel combusted, in 

scf CO2 per mmBtu.

(E) The annual average HHV value used in Equation C13 of this subpart, for each type of fossil fuel combusted, 

in Btu/lb, Btu/gal, or Btu/scf, as appropriate.

(F) The total quantity of each type of fossil fuel 

combusted during the reporting year, in lb, gallons, or 

scf, as appropriate.

(G) Annual biogenic CO2 mass emissions, in metric 

tons. 

(x) When ASTM methods D7459-08 and D6866-08 are used 

to determine the biogenic portion of the annual CO2
211

emissions from MSW combustion, as described in §98.34(d), 

report:

(A) The results of each quarterly sample analysis, 

expressed as a decimal fraction (e.g., if the biogenic 

fraction of the CO2 emissions from MSW combustion is 30 

percent, report 0.30).

(B) The annual biogenic CO2 mass emissions from MSW 

combustion, in metric tons.

(xi) When ASTM methods D7459-08 and D6866-08 are used

in accordance with §98.34(e) to determine the biogenic 

portion of the annual CO2 emissions from a unit that cofires biogenic fuels (or partly-biogenic fuels, including 

tires if you are electing to report biogenic CO2 emissions 

from tire combustion) and non-biogenic fuels, you shall 

report the results of each quarterly sample analysis, 

expressed as a decimal fraction (e.g., if the biogenic 

fraction of the CO2 emissions is 30 percent, report 0.30).

(3) Within 30 days of receipt of a written request 

from the Administrator, you shall submit explanations of 

the following: 

(i) An explanation of how company records are used to 

quantify fuel consumption, if the Tier 1 or Tier 2 

Calculation Methodology is used to calculate CO2 emissions.
212

(ii) An explanation of how company records are used 

to quantify fuel consumption, if solid fuel is combusted 

and the Tier 3 Calculation Methodology is used to calculate 

CO2 emissions. 

(iii) An explanation of how sorbent usage is 

quantified.

(iv) An explanation of how company records are used 

to quantify fossil fuel consumption in units that uses CEMS 

to quantify CO2 emissions and combusts both fossil fuel and 

biomass. 

(v) An explanation of how company records are used to 

measure steam production, when it is used to calculate CO2

mass emissions under §98.33(a)(2)(iii) or to quantify solid 

fuel usage under §98.33(c)(3). 

(4) Within 30 days of receipt of a written request 

from the Administrator, you shall submit the verification 

data and information described in paragraphs (e)(2)(iii), 

(e)(2)(v), and (e)(2)(vii) of this section. 

§98.37 Records That Must be Retained. 

In addition to the requirements of §98.3(g), you must 

retain the applicable records specified in §§98.34(f) and 

(g), 98.35(b), and 98.36(e). 

§98.38 Definitions.
213

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part.

Table C-1 to Subpart C—Default CO2 Emission Factors and High 

Heat Values for Various Types of Fuel

Fuel Type Default High 

Heat Value

Default CO2 Emission 

Factor

Coal and coke mmBtu/short 

ton

kg CO2 /mmBtu

Anthracite 25.09 103.54

Bituminous 24.93 93.40

Subbituminous 17.25 97.02

Lignite 14.21 96.36

Coke 24.80 102.04

Mixed (Commercial sector) 21.39 95.26

Mixed (Industrial coking) 26.28 93.65

Mixed (Industrial sector) 22.35 93.91

Mixed (Electric Power sector) 19.73 94.38

Natural gas mmBtu/scf kg CO2 /mmBtu

(Weighted U.S. Average) 1.028 x 10-3 53.02

Petroleum products mmBtu/gallon kg CO2 /mmBtu

Distillate Fuel Oil No. 1 0.139 73.25

Distillate Fuel Oil No. 2 0.138 73.96

Distillate Fuel Oil No. 4 0.146 75.04

Residual Fuel Oil No. 5 0.140 72.93

Residual Fuel Oil No. 6 0.150 75.10

Waste Oil 0.135 74.00

Kerosene 0.135 75.20

Liquefied petroleum gases (LPG) 0.092 62.98

Propane 0.091 61.46

Propylene 0.091 65.95

Ethane 0.096 62.64

Ethanol 0.084 68.44

Ethylene 0.100 67.43

Isobutane 0.097 64.91

Isobutylene 0.103 67.74

Butane 0.101 65.15

Butylene 0.103 67.73

Naphtha (<401 deg F) 0.125 68.02

Natural Gasoline 0.110 66.83

Other Oil (>401 deg F) 0.139 76.22

Pentanes Plus 0.110 70.02

Petrochemical Feedstocks 0.129 70.97

Petroleum Coke 0.143 102.41

Special Naphtha 0.125 72.34

Unfinished Oils 0.139 74.49

Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27

Motor Gasoline 0.125 70.22

Aviation Gasoline 0.120 69.25
214

Table C-1 to Subpart C—Default CO2 Emission Factors and High 

Heat Values for Various Types of Fuel

Fuel Type Default High 

Heat Value

Default CO2 Emission 

Factor

Kerosene-Type Jet Fuel 0.135 72.22

Asphalt and Road Oil 0.158 75.36

Crude Oil 0.138 74.49

Other fuels (solid) mmBtu/short 

ton

kg CO2 /mmBtu

Municipal Solid Waste 9.951 90.7

Tires 26.87 85.97

Plastics 38.00 75.00

Petroleum Coke 30.00 102.41

Other fuels (gaseous) mmBtu/scf kg CO2 /mmBtu

Blast Furnace Gas 0.092 x 10-3 274.32

Coke Oven Gas 0.599 x 10-3 46.85

Propane Gas 2.516 x 10-3 61.46

Fuel Gas2 1.388 x 10-3 59.00

Biomass fuels - solid mmBtu/short 

ton

kg CO2 /mmBtu

Wood and Wood Residuals 15.38 93.80

Agricultural Byproducts 8.25 118.17

Peat 8.00 111.84

Solid Byproducts 25.83 105.51

Biomass fuels - gaseous mmBtu/scf kg CO2 /mmBtu

Biogas (Captured methane) 0.841 x 10-3 52.07

Biomass fuels - liquid mmBtu/gallon kg CO2 /mmBtu

Ethanol 0.084 68.44

Biodiesel 0.128 73.84

Rendered Animal Fat 0.125 71.06

Vegetable Oil 0.120 81.55

1

Use of this default HHV is allowed only for units that combust 

MSW, do not generate steam, and are allowed to use Tier 1.

2

Reporters subject to subpart X of this part that are complying 

with §98.243(d) or subpart Y of this part may only use the 

default HHV and the default CO2 emission factor for fuel gas 

combustion under the conditions prescribed in §98.243(d)(2)(i) 

and (d)(2)(ii) and §98.252(a)(1) and (a)(2), respectively. 

Otherwise, Tier 3 (Equation C-5) or Tier 4 must be used.

Table C-2 to Subpart C—Default CH4 and N2O Emission Factors 

for Various Types of Fuel. 

Fuel Type

Default CH4

Emission Factor 

(kg CH4 /mmBtu)

Default N2O 

Emission Factor (kg 

N2O/mmBtu)

Coal and Coke (All fuel 

types in Table C-1)

1.1 x 10-02 1.6 x 10-03

Natural Gas 1.0 x 10-03 1.0 x 10-04
215

Fuel Type

Default CH4

Emission Factor 

(kg CH4 /mmBtu)

Default N2O 

Emission Factor (kg 

N2O/mmBtu)

Petroleum (All fuel types 

in Table C-1)

3.0 x 10-03 6.0 x 10-04

Municipal Solid Waste 3.2 x 10-02 4.2 x 10-03

Tires 3.2 x 10-02 4.2 x 10-03

Blast Furnace Gas 2.2 x 10-05 1.0 x 10-04

Coke Oven Gas 4.8 x 10-04 1.0 x 10-04

Biomass Fuels - Solid (All 

fuel types in Table C-1)

3.2 x 10-02 4.2 x 10-03

Biogas 3.2 x 10-03 6.3 x 10-04

Biomass Fuels – Liquid 

(All fuel types in Table 

C-1)

1.1 x 10-03 1.1 x 10-04

Note: Those employing this table are assumed to fall under the IPCC 

definitions of the “Energy Industry” or “Manufacturing Industries and 

Construction”. In all fuels except for coal the values for these two 

categories are identical. For coal combustion, those who fall within 

the IPCC “Energy Industry” category may employ a value of 1 g of 

CH4/MMBtu.

Subpart D—Electricity Generation

§98.40 Definition of the source category.

(a) The electricity generation source category 

comprises electricity generating units that are subject to 

the requirements of the Acid Rain Program and any other 

electricity generating units that are required to monitor 

and report to EPA CO2 mass emissions year-round according to 

40 CFR part 75.

(b) This source category does not include portable 

equipment, emergency equipment, or emergency generators, as 

defined in §98.6.

§98.41 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains one or more electricity generating 
216

units and the facility meets the requirements of 

§98.2(a)(1).

§98.42 GHGs to report.

(a) For each electricity generating unit that is 

subject to the requirements of the Acid Rain Program or is 

otherwise required to monitor and report to EPA CO2

emissions year-round according to 40 CFR part 75, you must 

report under this subpart the annual mass emissions of CO2, 

N2O, and CH4 by following the requirements of this subpart. 

(b) For each electricity generating unit that is not 

subject to the Acid Rain Program or otherwise required to 

monitor and report to EPA CO2 emissions year-round according 

to 40 CFR part 75, you must report under subpart C of this 

part (General Stationary Fuel Combustion Sources) the 

emissions of CO2, CH4, and N2O by following the requirements 

of subpart C.

(c) For each stationary fuel combustion unit that 

does not generate electricity, you must report under 

subpart C of this part (General Stationary Fuel Combustion 

Sources) the emissions of CO2, CH4, and N2O by following the 

requirements of subpart C of this part.

§98.43 Calculating GHG emissions.

Continue to monitor and report CO2 mass emissions as 

required under §75.13 or section 2.3 of apppendix G to 40 
217

CFR part 75, and §75.64. Calculate CO2, CH4, and N2O 

emissions as follows: 

(a) Convert the cumulative annual CO2 mass emissions 

reported in the fourth quarter electronic data report 

required under §75.64 from units of short tons to metric 

tons. To convert tons to metric tons, divide by 1.1023.

(b) Calculate and report annual CH4 and N2O mass 

emissions under this subpart by following the applicable 

method specified in §98.33(c).

§98.44 Monitoring and QA/QC requirements 

Follow the applicable quality assurance procedures for 

CO2 emissions in appendices B, D, and G to 40 CFR part 75.

§98.45 Procedures for estimating missing data.

Follow the applicable missing data substitution 

procedures in 40 CFR part 75 for CO2 concentration, stack 

gas flow rate, fuel flow rate, high heating value, and fuel 

carbon content.

§98.46 Data reporting requirements. 

The annual report shall comply with the data reporting 

requirements specified in §98.36(d)(1).

§98.47 Records that must be retained. 

You shall comply with the recordkeeping requirements 

of §§98.3(g) and 98.37. Records retained under §75.57(h) 

of this chapter for missing data events satisfy the 
218

recordkeeping requirements of §98.3(g)(4) for those same 

events.

§98.48 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Subpart F—Aluminum Production

§98.60 Definition of the source category.

(a) A primary aluminum production facility 

manufactures primary aluminum using the Hall-Héroult 

manufacturing process. The primary aluminum manufacturing 

process comprises the following operations:

(1) Electrolysis in prebake and Søderberg cells.

(2) Anode baking for prebake cells.

(b) This source category does not include 

experimental cells or research and development process 

units.

§98.61 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains an aluminum production process and 

the facility meets the requirements of either §98.2(a)(1) 

or (a)(2).

§98.62 GHGs to report.

You must report:
219

(a) Perfluoromethane (CF4), and perfluoroethane (C2F6) 

emissions from anode effects in all prebake and Søderberg 

electrolysis cells.

(b) CO2 emissions from anode consumption during 

electrolysis in all prebake and Søderberg electrolysis 

cells.

(c) CO2 emissions from on-site anode baking.

(d) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, N2O, and CH4 emissions from each stationary fuel 

combustion unit by following the requirements of subpart C. 

§98.63 Calculating GHG emissions.

(a) The annual value of each PFC compound (CF4, C2F6)

shall be estimated from the sum of monthly values using 

Equation F-1 of this section:









12

1

m

m

EPFC Em (Eq. F-1)

Where:

EPFC = Annual emissions of each PFC compoundfrom 

aluminum production (metric tons PFC).

Em = Emissions of the individual PFC compound from 

aluminum production for the month “m” (metric 

tons PFC).

(b) Use Equation F-2 of this section to estimate CF4

emissions from anode effect duration or Equation F-3 of 

this section to estimate CF4 emissions from overvoltage, and 

use Equation F-4 of this section to estimate C2F6 emissions 
220

from anode effects from each prebake and Søderberg 

electrolysis cell.

ECF4 = SCF4 × AEM × MP × 0.001 (Eq. F-2)

Where:

ECF4 = Monthly CF4 emissions from aluminum production 

(metric tons CF4).

SCF4 = The slope coefficient ((kg CF4/metric ton Al)/(AEMins/cell-day)).

AEM = The anode effect minutes per cell-day (AEMins/cell-day).

MP = Metal production (metric tons Al), where AEM 

and MP are calculated monthly.

ECF4 = EFCF4 × MP × 0.001 (Eq. F-3)

Where:

ECF4 = Monthly CF4 emissions from aluminum production 

(metric tons CF4).

EFCF4 = The overvoltage emission factor (kg CF4/metric ton 

Al).

MP = Metal production (metric tons Al), where MP is 

calculated monthly.

EC2F6 = ECF4 × FC2F6/CF4 × 0.001 (Eq. F-4)

Where:

EC2F6 = Monthly C2F6 emissions from aluminum production 

(metric tons C2F6).

ECF4 = CF4 emissions from aluminum production(kg CF4). 

FC2F6/CF4 = The weight fraction of C2F6/CF4 (kg C2F6/kg CF4).

0.001 = Conversion factor from kg to metric tons, where 

ECF4 is calculated monthly.

(c) You must calculate and report the annual process 

CO2 emissions from anode consumption during electrolysis and 
221

anode baking of prebake cells using either the procedures 

in paragraph (d) of this section, the procedures in 

paragraphs (e) and (f) of this section, or the procedures 

in paragraph (g) of this section.

(d) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining CEMS 

according to the Tier 4 Calculation Methodology in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources). 

(e) Use the following procedures to calculate CO2

emissions from anode consumption during electrolysis: 

(1) For Prebake cells: you must calculate CO2

emissions from anode consumption using Equation F-5 of this 

section:

ECO2 = NAC × MP ×([100 – Sa– Asha] / 100) × (44/12) (Eq. F-5)

Where:

ECO2 = Annual CO2 emissions from prebaked anode 

consumption (metric tons CO2).

NAC = Net annual prebaked anode consumption per metric 

ton Al (metric tons C/metric tons Al).

MP = Annual metal production (metric tons Al).

Sa = Sulfur content in baked anode (percent weight).

Asha = Ash content in baked anode(percent weight).

44/12 = Ratio of molecular weights, CO2 to carbon.
222

(2) For Søderberg cells you must calculate CO2

emissions using Equation F-6 of this section:

ECO2 = (PC × MP – [CSM × MP] / 1000 – BC / 100 × PC × 

MP × [Sp + Ashp + Hp] / 100 – [100 - BC] / 100 × PC × MP × 

[Sc + Ashc] / 100 – MP × CD) × (44/12) (Eq. F-6)

Where:

ECO2 = Annual CO2 emissions from paste consumption 

(metric ton CO2).

PC = Annual paste consumption (metric ton/metric ton 

Al).

MP = Annual metal production (metric ton Al).

CSM = Annual emissions of cyclohexane soluble matter 

(kg/metric ton Al).

BC = Binder content of paste (percent weight).

Sp = Sulfur content of pitch (percent weight).

Ashp = Ash content of pitch (percent weight).

Hp = Hydrogen content of pitch (percent weight).

Sc = Sulfur content in calcined coke (percent weight).

Ashc = Ash content in calcined coke (percent weight).

CD = Carbon in skimmed dust from Søderberg cells 

(metric ton C/metric ton Al).

44/12 = Ratio of molecular weights, CO2 to carbon.

(f) Use the following procedures to calculate CO2

emissions from anode baking of prebake cells:

(1) Use Equation F-7 of this section to calculate 

emissions from pitch volatiles combustion.

ECO2PV = (GA – Hw – BA – WT) × (44/12) (Eq. F-7)

Where: 

ECO2PV = Annual CO2 emissions from pitch volatiles 

combustion (metric tons CO2).
223

GA = Initial weight of green anodes (metric tons).

Hw = Annual hydrogen content in green anodes (metric 

tons).

BA = Annual baked anode production (metric tons).

WT = Annual waste tar collected (metric tons).

44/12 = Ratio of molecular weights, CO2 to carbon.

(2) Use Equation F-8 of this section to calculate 

emissions from bake furnace packing material.

ECO2PC = PCC × BA × ([100 – Spc – Ashpc] / 100) × (44/12)(Eq. F-8)

Where:

ECO2PC = Annual CO2 emissions from bake furnace packing 

material (metric tons CO2).

PCC = Annual packing coke consumption (metric 

tons/metric ton baked anode).

BA = Annual baked anode production (metric tons).

Spc = Sulfur content in packing coke (percent weight).

Ashpc = Ash content in packing coke (percent weight).

44/12 = Ratio of molecular weights, CO2 to carbon.

(g) If process CO2 emissions from anode consumption 

during electrolysis or anode baking of prebake cells are 

vented through the same stack as any combustion unit or 

process equipment that reports CO2 emissions using a CEMS 

that complies with the Tier 4 Calculation Methodology in 

subpart C of this part (General Stationary Fuel Combustion 

Sources), then the calculation methodology in paragraphs

(d) and (e) of this section shall not be used to calculate 

those process emissions. The owner or operation shall 

report under this subpart the combined stack emissions 
224

according to the Tier 4 Calculation Methodology in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources).

§98.64 Monitoring and QA/QC requirements. 

(a) Effective one year after publication of the rule 

for smelters with no prior measurement or effective three 

years after publication for facilities with historic 

measurements, the smelter-specific slope coefficients, 

overvoltage emission factors, and weight fractions used in 

Equations F-2, F-3, and F-4 of this subpart must be 

measured in accordance with the recommendations of the 

EPA/IAI Protocol for Measurement of Tetrafluoromethane (CF4) 

and Hexafluoroethane (C2F6) Emissions from Primary Aluminum 

Production (2008), except the minimum frequency of 

measurement shall be every 10 years unless a change occurs 

in the control algorithm that affects the mix of types of 

anode effects or the nature of the anode effect termination 

routine. Facilities which operate at less than 0.2 anode 

effect minutes per cell day or operate with less than 1.4mV 

anode effect overvoltage can use either smelter-specific 

slope coefficients or the technology specific default 

values in Table F-1 of this subpart.
225

(b) The minimum frequency of the measurement and 

analysis is annually except as follows:

(i) Monthly for anode effect minutes per cell day (or 

anode effect overvoltage and current efficiency).

(ii) Monthly for aluminum production. 

(iii) Smelter-specific slope coefficients, 

overvoltage emission factors, and weight fractions 

according to paragraph (a) of this section. 

(c) Sources may use either smelter-specific values 

from annual measurements of parameters needed to complete 

the equations in §98.63 (e.g., sulfur, ash, and hydrogen 

contents) or the default values shown in Table F-2 of this 

subpart. 

§98.65 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 

operation or if a required sample measurement is not 

taken), a substitute data value for the missing parameter 

shall be used in the calculations, according to the 

following requirements:
226

(a) Where anode or paste consumption data are 

missing, CO2 emissions can be estimated from aluminum 

production per Equation F-8 of this section. 

ECO2 = EFp x MPp + EFs x MPs (Eq. F-8)

Where: 

ECO2 = CO2 emissions from anode and/or paste consumption,

metric tons CO2.

EFp = Prebake technology specific emission factor (1.6 

metric tons CO2/metric ton aluminum produced).

MPp = Metal production from prebake process (metric tons 

Al).

EFs = Søderberg technology specific emission factor (1.7 

metric tons CO2/metric ton Al produced).

MPs = Metal production from Søderberg process (metric 

tons Al).

(b) For other parameters, use the average of the two 

most recent data points after the missing data. 

§98.66 Data reporting requirements. 

In addition to the information required by §98.3(c), 

you must report the following information at the facility 

level: 

(a) Annual aluminum production in metric tons.

(b) Type of smelter technology used. 

(c) The following PFC-specific information on an 

annual basis: 

(1) Perfluoromethane emissions and perfluoroethane 

emissions from anode effects in all prebake and all 

Søderberg electrolysis cells combined. 
227

(2) Anode effect minutes per cell-day (AE-mins/cellday), anode effect frequency (AE/cell-day), anode effect 

duration (minutes). (Or anode effect overvoltage factor 

((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage 

(mV/cell day), current efficiency (%).)

(3) Smelter-specific slope coefficients (or 

overvoltage emission factors) and the last date when the 

smelter-specific-slope coefficients (or overvoltage 

emission factors) were measured.

(d) Method used to measure the frequency and duration 

of anode effects (or overvoltage).

(e) The following CO2-specific information for prebake 

cells: 

(1) Annual anode consumption.

(2) Annual CO2 emissions from the smelter. 

(f) The following CO2-specific information for 

Søderberg cells: 

(1) Annual paste consumption. 

(2) Annual CO2 emissions from the smelter.

(g) Smelter-specific inputs to the CO2 process 

equations (e.g., levels of sulfur and ash) that were used 

in the calculation, on an annual basis. 

(h) Exact data elements required will vary depending 

on smelter technology (e.g., point-feed prebake or 
228

Søderberg) and process control technology (e.g., Pechiney 

or other). 

§98.67 Records that must be retained. 

In addition to the information required by §98.3(g), 

you must retain the following records:

(a) Monthly aluminum production in metric tons. 

(b) Type of smelter technology used. 

(c) The following PFC-specific information on a 

monthly basis: 

(1) Perfluoromethane and perfluoroethane emissions 

from anode effects in prebake and Søderberg electrolysis 

cells. 

(2) Anode effect minutes per cell-day (AE-mins/cellday), anode effect frequency (AE/cell-day), anode effect 

duration (minutes). (Or anode effect overvoltage factor 

((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage 

(mV/cell day), current efficiency (%).)) 

(3) Smelter-specific slope coefficients and the last 

date when the smelter-specific-slope coefficients were 

measured.

(d) Method used to measure the frequency and duration 

of anode effects (or to measure anode effect overvoltage 

and current efficiency).
229

(e) The following CO2-specific information for prebake 

cells: 

(1) Annual anode consumption.

(2) Annual CO2 emissions from the smelter. 

(f) The following CO2-specific information for 

Søderberg cells: 

(1) Annual paste consumption.

(2) Annual CO2 emissions from the smelter.

(g) Smelter-specific inputs to the CO2 process 

equations (e.g., levels of sulfur and ash) that were used 

in the calculation, on an annual basis. 

(h) Exact data elements required will vary depending 

on smelter technology (e.g., point-feed prebake or 

Søderberg) and process control technology (e.g., Pechiney 

or other).

§98.68 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Table F-1 to Subpart F—Slope and Overvoltage Coefficients 

for the Calculation of PFC Emissions from Aluminum 

Production

Technology

CF4 Slope 

Coefficient

[(kg CF4/metric 

ton Al)/(AEMins/cell-day)]

CF4 Overvoltage 

Coefficient

[(kg CF4/metric 

ton Al)/(mV)]

Weight 

Fraction 

C2F6/CF4

[(kg C2F6/kg 

CF4)]
230

Technology

CF4 Slope 

Coefficient

[(kg CF4/metric 

ton Al)/(AEMins/cell-day)]

CF4 Overvoltage 

Coefficient

[(kg CF4/metric 

ton Al)/(mV)]

Weight 

Fraction 

C2F6/CF4

[(kg C2F6/kg 

CF4)]

Center 

Worked 

Prebake 

(CWPB)

0.143 1.16 0.121

Side 

Worked 

Prebake 

(SWPB)

0.272 3.65 0.252

Vertical 

Stud 

Søderberg 

(VSS)

0.092 NA 0.053

Horizontal

Stud 

Søderberg 

(HSS)

0.099 NA 0.085

Table F-2 to Subpart F—Default Data Sources for Parameters 

Used for CO2 Emissions

CO2 Emissions from Prebake Cells (CWPB and SWPB)

Parameter Data Source

MP: metal production (metric 

tons Al) Individual facility records

NAC: net annual prebaked anode 

consumption per metric ton Al 

(metric tons C/metric tons Al)

Individual facility records

Sa: sulfur content in baked 

anode (percent weight) 2.0

Asha: ash content in baked 

anode(percent weight) 0.4

CO2 Emissions from Søderberg Cells (VSS and HSS)

Parameter Data Source

MP: metal production (metric 

tons Al) Individual facility records

PC: annual paste consumption 

(metric ton/metric ton Al) Individual facility records

CSM: annual emissions of 

cyclohexane soluble matter 

(kg/metric ton Al)

HSS: 4.0

VSS: 0.5

BC: binder content of paste 

(percent weight)

Dry Paste: 24

Wet Paste: 27
231

Sp: sulfur content of pitch 

(percent weight) 0.6

Ashp: ash content of pitch 

(percent weight) 0.2

Hp: hydrogen content of pitch 

(percent weight) 3.3

Sc: sulfur content in calcined 

coke (percent weight) 1.9

Ashc: ash content in calcined 

coke (percent weight) 0.2

CD: carbon in skimmed dust 

from Søderberg cells (metric

ton C/metric ton Al)

0.01

CO2 Emissions from Pitch Volatiles Combustion (CWPB and SWPB)

Parameter Data Source

GA: initial weight of green 

anodes (metric tons) Individual facility records

Hw: annual hydrogen content in 

green anodes (metric tons) 0.005 × GA

BA: annual baked anode 

production (metric tons) Individual facility records

WT: annual waste tar collected 

(metric tons)

(a) Riedhammer furnaces

(b) all other furnaces

(a) 0.005 × GA

(b) insignificant

CO2 Emissions from Bake Furnace Packing Materials (CWPB and SWPB)

Parameter Data Source

PCC: annual packing coke 

consumption (metric tons/metric 

ton baked anode)

0.015

BA: annual baked anode 

production (metric tons) Individual facility records

Spc: sulfur content in packing 

coke (percent weight) 2

Ashpc: ash content in packing 

coke (percent weight) 2.5

Subpart G—Ammonia Manufacturing

§98.70 Definition of Source Category.

The ammonia manufacturing source category comprises 

the process units listed in paragraphs (a) and (b) of this 

section. 
232

(a) Ammonia manufacturing processes in which ammonia 

is manufactured from a fossil-based feedstock produced via 

steam reforming of a hydrocarbon.

(b) Ammonia manufacturing processes in which ammonia 

is manufactured through the gasification of solid and 

liquid raw material.

§98.71 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains an ammonia manufacturing process and 

the facility meets the requirements of either §98.2(a)(1) 

or (2).

§98.72 GHGs to report.

You must report:

(a) CO2 process emissions from steam reforming of a 

hydrocarbon or the gasification of solid and liquid raw 

material, reported for each ammonia manufacturing process 

unit following the requirements of this subpart (CO2 process 

emissions reported under this subpart may include CO2 that 

is later consumed on-site for urea production, and 

therefore is not released to the ambient air from the 

ammonia manufacturing process unit).

(b) CO2, CH4, and N2O emissions from each stationary 

fuel combustion unit. You must report these emissions 

under subpart C of this part (General Stationary Fuel 
233

Combustion Sources), by following the requirements of 

subpart C, except that for ammonia manufacturing processes 

subpart C does not apply to any CO2 resulting from 

combustion of the waste recycle stream (commonly referred 

to as the purge gas stream).

(c) CO2 emissions collected and transferred off site 

under subpart PP (Suppliers of CO2), following the 

requirements of subpart PP.

§98.73 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each ammonia manufacturing process unit 

using the procedures in either paragraph (a) or (b) of this 

section.

(a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining CEMS 

according to the Tier 4 Calculation Methodology specified 

in §98.33(a)(4) and all associated requirements for Tier 4 

in subpart C of this part (General Stationary Fuel 

Combustion Sources). 

(b) Calculate and report under this subpart process 

CO2 emissions using the procedures in paragraphs (b)(1) 

through (b)(5) of this section for gaseous feedstock, 

liquid feedstock, or solid feedstock, as applicable. 
234

(1) Gaseous feedstock. You must calculate, from each 

ammonia manufacturing unit, the CO2 process emissions from 

gaseous feedstock according to Equation G-1 of this 

section: 

) 0.001

MVC

MW

Fdstk CC

12

44

CO ( n,k n

12

n 1

2,G,k     



∑ (Eq. G-1)

Where:

CO2,G,k = Annual CO2 emissions arising from gaseous 

feedstock consumption (metric tons). 

Fdstkn = Volume of the gaseous feedstock used in month n 

(scf of feedstock).

CCn = Carbon content of the gaseous feedstock, for 

month n, (kg C per kg of feedstock), determined 

according to 98.74(c). 

MW = Molecular weight of the gaseous feedstock 

(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at standard conditions).

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons. 

k = Processing unit.

n = Number of month

(2) Liquid feedstock. You must calculate, from each 

ammonia manufacturing unit, the CO2 process emissions from 

liquid feedstock according to Equation G-2 of this section:

Fdstk CC ) 0.001

12

44

CO ( n,k n

12

n 1

2,L,k    



∑ (Eq. G-2)

Where:

CO2,L,k = Annual CO2 emissions arising from liquid 

feedstock consumption (metric tons). 
235

Fdstkn = Volume of the liquid feedstock used in month n 

(gallons of feedstock).

CCn = Carbon content of the liquid feedstock, for 

month n, (kg C per gallon of feedstock) 

determined according to 98.74(c).

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

k = Processing unit.

n = Number of month

(3) Solid feedstock. You must calculate, from each 

ammonia manufacturing unit, the CO2 process emissions from 

solid feedstock according to Equation G-3 of this section:

Fdstk CC ) 0.001

12

44

CO ( n,k n

12

n 1

2,S,k    



∑ (Eq. G-3)

Where:

CO2,S,k = Annual CO2 emissions arising from solid 

feedstock consumption (metric tons). 

Fdstkn = Mass of the solid feedstock used in month n (kg 

of feedstock).

CCn = Carbon content of the solid feedstock, for 

month n, (kg C per kg of feedstock), determined 

according to 98.74(c). 

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

K = Processing unit.

n = Number of month.

(4) You must calculate the annual process CO2

emissions from each ammonia processing unit k at your 

facility summing emissions, as applicable from Equation G1, G-2, and G-3 of this section using Equation G-4.
236

ECO2 =k CO2,G + CO2,S + CO2,L (Eq. G-4)

Where:

ECO2k= Annual CO2 emissions from each ammonia 

processing unit k (metric tons).

k = Processing unit.

(5) You must determine the combined CO2 emissions from 

all ammonia processing units at your facility using 

Equation G-5 of this section.

∑

n

k=1

CO2 = ECO2 k(Eq. G-5)

Where:

CO2 = Annual combined CO2 emissions from all ammonia 

processing units (metric tons) (CO2 process 

emissions reported under this subpart may 

include CO2 that is later consumed on-site for

urea production, and therefore is not released 

to the ambient air from the ammonia 

manufacturing process unit(s)).

ECO2k= Annual CO2 emissions from each ammonia 

processing unit (metric tons).

k = Processing unit.

n = Total number of ammonia processing units.

(c) If GHG emissions from an ammonia manufacturing 

unit are vented through the same stack as any combustion 

unit or process equipment that reports CO2 emissions using a 

CEMS that complies with the Tier 4 Calculation Methodology 

in subpart C of this part (General Stationary Fuel 

Combustion Sources), then the calculation methodology in 
237

paragraph (b) of this section shall not be used to 

calculate process emissions. The owner or operator shall 

report under this subpart the combined stack emissions 

according to the Tier 4 Calculation Methodology in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part.

§98.74 Monitoring and QA/QC requirements.

(a) You must continuously measure the quantity of 

gaseous or liquid feedstock consumed using a flow meter. 

The quantity of solid feedstock consumed can be obtained 

from company records and aggregated on a monthly basis.

(b) You must document the procedures used to ensure 

the accuracy of the estimates of feedstock consumption. 

(c) You must determine monthly carbon contents and 

the average molecular weight of each feedstock consumed 

from reports from your supplier. As an alternative to using 

supplier information on carbon contents, you can also 

collect a sample of each feedstock on a monthly basis and 

analyze the carbon content and molecular weight of the fuel 

using any of the following methods listed in paragraphs 

(c)(1) through (c)(8) of this section, as applicable. 

(1) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7).
238

(2) ASTM D1946-90 (Reapproved 2006) Standard Practice 

for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7).

(3) ASTM D2502-04 (Reapproved 2002) Standard Test 

Method for Estimation of Mean Relative Molecular Mass of 

Petroleum Oils from Viscosity Measurements (incorporated by 

reference, see §98.7).

(4) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure (incorporated by reference, see §98.7).

(5) ASTM D3238-95 (Reapproved 2005) Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M

Method (incorporated by reference, see §98.7).

(6) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7).

(7) ASTM D3176-89 (Reapproved 2002) Standard Practice 

for Ultimate Analysis of Coal and Coke (incorporated by 

reference, see §98.7).

(8) ASTM D5373-08 Standard Methods for Instrumental 

Determination of Carbon, Hydrogen, and Nitrogen in 
239

Laboratory Samples of Coal (incorporated by reference, see 

§98.7). 

(d) Calibrate all oil and gas flow meters that are 

used to measure liquid and gaseous feedstock volumes and 

flow rates (except for gas billing meters) according to the 

monitoring and QA/QC requirements for the Tier 3 

methodology in §98.34(b)(1). Perform oil tank drop 

measurements (if used to quantify feedstock volumes) 

according to §98.34(b)(2).

(e) For quality assurance and quality control of the 

supplier data, on an annual basis, you must measure the 

carbon contents of a representative sample of the 

feedstocks consumed using the appropriate ASTM Method as 

listed in paragraphs (c)(1) through (c)(8) of this 

section.

(f) [Reserved]

(g) If CO2 from ammonia production is used to produce 

urea at the same facility, you must determine the quantity 

of urea produced using methods or plant instruments used 

for accounting purposes (such as sales records). You must 

document the procedures used to ensure the accuracy of the 

estimates of urea produced.

§98.75 Procedures for estimating missing data. 
240

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever the monitoring and quality assurance procedures in 

§98.74 cannot be followed (e.g., if a meter malfunctions 

during unit operation), a substitute data value for the 

missing parameter shall be used in the calculations 

following paragraphs (a) and (b) of this section. You must 

document and keep records of the procedures used for all 

such estimates.

(a) For missing data on monthly carbon contents of 

feedstock, the substitute data value shall be the 

arithmetic average of the quality-assured values of that 

carbon content in the month preceding and the month 

immediately following the missing data incident. If no 

quality-assured data are available prior to the missing 

data incident, the substitute data value shall be the first 

quality-assured value for carbon content obtained in the 

month after the missing data period.

(b) For missing feedstock supply rates used to 

determine monthly feedstock consumption, you must determine 

the best available estimate(s) of the parameter(s), based 

on all available process data.

§98.76 Data reporting requirements. 
241

In addition to the information required by §98.3(c), 

each annual report must contain the information specified 

in paragraphs (a) and (b) of this section, as applicable 

for each ammonia manufacturing process unit.

(a) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36 for the Tier 4 Calculation Methodology and the 

following information in this paragraph (a):

(1) Annual quantity of each type of feedstock 

consumed for ammonia manufacturing (scf of feedstock or 

gallons of feedstock or kg of feedstock).

(2) Method used for determining quantity of feedstock 

used.

(b) If a CEMS is not used to measure emissions, then 

you must report the following information:

(1) Annual CO2 process emissions (metric tons) for 

each ammonia manufacturing process unit.

(2) Monthly quantity of each type of feedstock 

consumed for ammonia manufacturing for each ammonia 

processing unit (scf of feedstock or gallons of feedstock 

or kg of feedstock).

(3) Method used for determining quantity of monthly 

feedstock used.
242

(4) Whether carbon content for each feedstock for 

month n is based on reports from the supplier or analysis 

of carbon content.

(5) If carbon content of feedstock for month n is 

based on analysis, the test method used.

(6) Sampling analysis results of carbon content of 

feedstock as determined for QA/QC of supplier data under 

§98.74(e).

(7) If a facility uses gaseous feedstock, the carbon 

content of the gaseous feedstock, for month n, (kg C per kg 

of feedstock).

(8) If a facility uses gaseous feedstock, the 

molecular weight of the gaseous feedstock (kg/kg-mole).

(9) If a facility uses gaseous feedstock, the molar 

volume conversion factor of the gaseous feedstock (scf per 

kg-mole).

(10) If a facility uses liquid feedstock, the carbon 

content of the liquid feedstock, for month n, (kg C per 

gallon of feedstock).

(11) If a facility uses solid feedstock, the carbon 

content of the solid feedstock, for month n, (kg C per kg 

of feedstock).

(12) Annual urea production (metric tons) and method 

used to determine urea production.
243

(13) CO2 from the steam reforming of a hydrocarbon or 

the gasification of solid and liquid raw material at the 

ammonia manufacturing process unit used to produce urea and 

the method used to determine the CO2 consumed in urea 

production.

§98.77 Records that must be retained. 

In addition to the records required by §98.3(g), you 

must retain the following records specified in paragraphs 

(a) and (b) of this section for each ammonia manufacturing 

unit.

(a) If a CEMS is used to measure emissions, retain 

records of all feedstock purchases in addition to the 

requirements in §98.37 for the Tier 4 Calculation 

Methodology.

(b) If a CEMS is not used to measure process CO2 

emissions, you must also retain the records specified in 

paragraphs (b)(1) through (b)(2) of this section:

(1) Records of all analyses and calculations 

conducted for reported data as listed in §98.76(b).

(2) Monthly records of carbon content of feedstock 

from supplier and/or all analyses conducted of carbon 

content.

§98.78 Definitions.
244

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Subpart P—Hydrogen Production

§98.160 Definition of the source category.

(a) A hydrogen production source category consists of 

facilities that produce hydrogen gas sold as a product to 

other entities. 

(b) This source category comprises process units that 

produce hydrogen by reforming, gasification, oxidation, 

reaction, or other transformations of feedstocks.

(c) This source category includes merchant hydrogen 

production facilities located within a petroleum refinery 

if they are not owned by, or under the direct control of, 

the refinery owner and operator. 

§98.161 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a hydrogen production process and 

the facility meets the requirements of either §98.2(a)(1) 

or (a)(2).

§98.162 GHGs to report.

You must report: 

(a) CO2 process emissions from each hydrogen 

production process unit.
245

(b) CO2, CH4 and N2O combustion emissions from each 

hydrogen production process unit. You must calculate and 

report these combustion emissions under subpart C of this 

part (General Stationary Fuel Combustion Sources) by 

following the requirements of subpart C.

(c) CO2, CH4, and N2O emissions from each stationary 

combustion unit other than hydrogen production process 

units. You must calculate and report these emissions under 

subpart C of this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C.

(d) For CO2 collected and transferred off site, you 

must follow the requirements of subpart PP of this part.

§98.163 Calculating GHG emissions.

You must calculate and report the annual process CO2

emissions from each hydrogen production process unit using 

the procedures specified in either paragraph (a) or (b) of 

this section.

(a) Continuous Emissions Montoring Systems (CEMS). 

Calculate and report under this subpart the process CO2

emissions by operating and maintaining CEMS according to 

the Tier 4 Calculation Methodology specified in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 

Sources). 
246

(b) Fuel and feedstock material balance approach. 

Calculate and report process CO2 emissions as the sum of the 

annual emissions associated with each fuel and feedstock 

used for hydrogen production by following paragraphs (b)(1) 

through (b)(3) of this section.

(1) Gaseous fuel and feedstock. You must calculate 

the annual CO2 process emissions from gaseous fuel and 

feedstock according to Equation P-1 of this section: 

* ) * 0.001

12

44 (

1

2 MVC

MW CO Fdstk n CCn

k

n

   



(Eq. P-1)

Where:

CO2 = Annual CO2 process emissions arising from 

fuel and feedstock consumption (metric 

tons/yr). 

Fdstkn = Volume of the gaseous fuel and feedstock 

used in month n (scf (at standard conditions 

of 68 °F and atmospheric pressure) of fuel 

and feedstock).

CCn = Average carbon content of the gaseous fuel 

and feedstock, from the results of one or 

more analyses for month n (kg carbon per kg 

of fuel and feedstock). 

MW = Molecular weight of the gaseous fuel and 

feedstock (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf 

per kg-mole at standard conditions).

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.
247

(2) Liquid fuel and feedstock. You must calculate 

the annual CO2 process emissions from liquid fuel and 

feedstock according to Equation P-2 of this section:

) * 0.001

12

44 (

1

2 n n

k

n

CO    Fdstk CC



(Eq. P-2)

Where:

CO2 = Annual CO2 emissions arising from fuel and 

feedstock consumption (metric tons/yr). 

Fdstkn = Volume of the liquid fuel and feedstock used in 

month n (gallons of fuel and feedstock).

CCn = Average carbon content of the liquid fuel and 

feedstock, from the results of one or more 

analyses for month n (kg carbon per gallon of 

fuel and feedstock).

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons. 

(3) Solid fuel and feedstock. You must calculate the 

annual CO2 process emissions from solid fuel and feedstock 

according to Equation P-3 of this section:

) * 0.001

12

44 (

1

2 n n

k

n

CO    Fdstk CC



(Eq.P-3)

Where: 

CO2 = Annual CO2 emissions from fuel and feedstock 

consumption in metric tons per month (metric 

tons/yr).

Fdstkn = Mass of solid fuel and feedstock used in month 

n (kg of fuel and feedstock). 

CCn = Average carbon content of the solid fuel and 

feedstock, from the results of one or more 

analyses for month n (kg carbon per kg of fuel 

and feedstock).

k = Months in the year.
248

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons. 

(c) If GHG emissions from a hydrogen production 

process unit are vented through the same stack as any 

combustion unit or process equipment that reports CO2

emissions using a CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the calculation 

methodology in paragraph (b) of this section shall not be 

used to calculate process emissions. The owner or operator 

shall report under this subpart the combined stack 

emissions according to the Tier 4 Calculation Methodology 

in §98.33(a)(4) and all associated requirements for Tier 4 

in subpart C of this part (General Stationary Fuel 

Combustion Sources).

§98.164 Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process 

units must be quality-assured as specified in paragraphs 

(a) or (b) of this section, as appropriate for each process 

unit:

(a) If a CEMS is used to measure GHG emissions, then 

the facility must comply with the monitoring and QA/QC 

procedures specified in §98.34(c).
249

(b) If a CEMS is not used to measure GHG emissions, 

then you must: 

(1) Calibrate all oil and gas flow meters that are 

used to measure liquid and gaseous feedstock volumes 

(except for gas billing meters) according to the monitoring 

and QA/QC requirements for the Tier 3 methodology in 

§98.34(b)(1). Perform oil tank drop measurements (if used 

to quantify liquid fuel or feedstock consumption) according 

to §98.34(b)(2). Calibrate all solids weighing equipment 

according to the procedures in §98.3(i).

(2) Determine the carbon content and the molecular 

weight annually of standard gaseous hydrocarbon fuels and 

feedstocks having consistent composition (e.g., natural 

gas). For other gaseous fuels and feedstocks (e.g., biogas, 

refinery gas, or process gas), weekly sampling and analysis 

is required to determine the carbon content and molecular 

weight of the fuel and feedstock. 

(3) Determine the carbon content of fuel oil, 

naphtha, and other liquid fuels and feedstocks at least 

monthly, except annually for standard liquid hydrocarbon 

fuels and feedstocks having consistent composition, or upon 

delivery for liquid fuels delivered by bulk transport 

(e.g., by truck or rail). 
250

(4) Determine the carbon content of coal, coke, and 

other solid fuels and feedstocks at least monthly, except 

annually for standard solid hydrocarbon fuels and 

feedstocks having consistent composition, or upon delivery 

for solid fuels delivered by bulk transport (e.g., by truck 

or rail). 

(5) You must use the following applicable methods to 

determine the carbon content for all fuels and feedstocks, 

and molecular weight of gaseous fuels and feedstocks. 

(i) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7).

(ii) ASTM D1946-90 (Reapproved 2006), Standard 

Practice for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7).

(iii) ASTM D2013-07 Standard Practice of Preparing 

Coal Samples for Analysis (incorporated by reference, see 

§98.7).

(iv) ASTM D2234/D2234M-07 Standard Practice for 

Collection of a Gross Sample of Coal (incorporated by 

reference, see §98.7).

(v) ASTM D2597-94 (Reapproved 2004) Standard Test 

Method for Analysis of Demethanized Hydrocarbon Liquid 
251

Mixtures Containing Nitrogen and Carbon Dioxide by Gas 

Chromatography (incorporated by reference, see §98.7).

(vi) ASTM D3176-89 (Reapproved 2002), Standard 

Practice for Ultimate Analysis of Coal and Coke 

(incorporated by reference, see §98.7). 

(vii) ASTM D3238-95 (Reapproved 2005), Standard Test 

Method for Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum Oils by the n-d-M 

Method (incorporated by reference, see §98.7).

(viii) ASTM D4057-06 Standard Practice for Manual 

Sampling of Petroleum and Petroleum Products (incorporated 

by reference, see §98.7).

(ix) ASTM D4177-95 (Reapproved 2005) Standard 

Practice for Automatic Sampling of Petroleum and Petroleum 

Products (incorporated by reference, see §98.7). 

(x) ASTM D5291-02 (Reapproved 2007), Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7).

(xi) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7). 
252

(xii) ASTM D6609-08 Standard Guide for Part-Stream 

Sampling of Coal (incorporated by reference, see §98.7).

(xiii) ASTM D6883-04 Standard Practice for Manual 

Sampling of Stationary Coal from Railroad Cars, Barges, 

Trucks, or Stockpiles (incorporated by reference, see 

§98.7).

(xiv) ASTM D7430-08ae1 Standard Practice for 

Mechanical Sampling of Coal (incorporated by reference, see 

§98.7).

(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7).

(xvi) GPA 2261–00 Analysis for Natural Gas and 

Similar Gaseous Mixtures by Gas Chromatography 

(incorporated by reference, see §98.7).

(xvii) ISO 3170: Petroleum Liquids -- Manual sampling 

– Third Edition (incorporated by reference, see §98.7).

(xviii) ISO 3171: Petroleum Liquids -- Automatic 

pipeline sampling – Second Edition (incorporated by 

reference, see §98.7).

(c) For units using the calculation methodologies 

described in this section, the records required under 

§98.3(g) must include both the company records and a 

detailed explanation of how company records are used to 

estimate the following:
253

(1) Fuel and feedstock consumption, when solid fuel 

and feedstock is combusted and a CEMS is not used to 

measure GHG emissions. 

(2) Fossil fuel consumption, when, pursuant to 

§98.33(e), the owner or operator of a unit that uses CEMS 

to quantify CO2 emissions and that combusts both fossil and 

biogenic fuels separately reports the biogenic portion of 

the total annual CO2 emissions. 

(3) Sorbent usage, if the methodology in §98.33(d) is 

used to calculate CO2 emissions from sorbent. 

(d) The owner or operator must document the 

procedures used to ensure the accuracy of the estimates of 

fuel and feedstock usage and sorbent usage (as applicable) 

in paragraph (b) of this section, including, but not 

limited to, calibration of weighing equipment, fuel and 

feedstock flow meters, and other measurement devices. The 

estimated accuracy of measurements made with these devices 

must also be recorded, and the technical basis for these 

estimates must be provided. 

§98.165 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 
254

operation), a substitute data value for the missing 

parameter must be used in the calculations as specified in 

paragraphs (a), (b), and (c) of this section:

(a) For each missing value of the monthly fuel and 

feedstock consumption, the substitute data value must be 

the best available estimate of the fuel and feedstock 

consumption, based on all available process data (e.g., 

hydrogen production, electrical load, and operating hours). 

You must document and keep records of the procedures used 

for all such estimates. 

(b) For each missing value of the carbon content or 

molecular weight of the fuel and feedstock, the substitute 

data value must be the arithmetic average of the qualityassured values of carbon contents or molecular weight of 

the fuel and feedstock immediately preceding and 

immediately following the missing data incident. If no 

quality-assured data on carbon contents or molecular weight 

of the fuel and feedstock are available prior to the 

missing data incident, the substitute data value must be 

the first quality-assured value for carbon contents or 

molecular weight of the fuel and feedstock obtained after 

the missing data period. You must document and keep 

records of the procedures used for all such estimates.
255

(c) For missing CEMS data, you must use the missing 

data procedures in §98.35. 

§98.166 Data reporting requirements. 

In addition to the information required by §98.3(c), 

each annual report must contain the information specified 

in paragraphs (a) or (b) of this section, as appropriate: 

(a) If a CEMS is used to measure CO2 emissions, then 

you must report the relevant information required under 

§98.36 for the Tier 4 Calculation Methodology and the 

following information in this paragraph (a):

(1) Unit identification number and annual CO2 process 

emissions.

(2) Annual quantity of hydrogen produced (metric 

tons) for each process unit and for all units combined. 

(3) Annual quantity of ammonia produced (metric 

tons), if applicable, for each process unit and for all 

units combined. 

(b) If a CEMS is not used to measure CO2 emissions, 

then you must report the following information for each 

hydrogen production process unit: 

(1) Unit identification number and annual CO2 process 

emissions.

(2) Monthly consumption of each fuel and feedstock 

used for hydrogen production and its type (scf of gaseous 
256

fuels and feedstocks, gallons of liquid fuels and 

feedstocks, kg of solid fuels and feedstocks). 

(3) Annual quantity of hydrogen produced (metric 

tons). 

(4) Annual quantity of ammonia produced, if 

applicable (metric tons). 

(5) Monthly analyses of carbon content for each fuel 

and feedstock used in hydrogen production (kg carbon/kg of

gaseous and solid fuels and feedstocks, (kg carbon per 

gallon of liquid fuels and feedstocks). 

(6) Monthly analyses of the molecular weight of 

gaseous fuels and feedstocks (kg/kg-mole) used, if any.

(c) Quarterly quantity of CO2 collected and 

transferred off site in either gas, liquid, or solid forms 

(kg), following the requirements of subpart PP of this 

part. 

(d) Annual quantity of carbon other than CO2 collected 

and transferred off site in either gas, liquid, or solid 

forms (kg carbon).

§98.167 Records that must be retained.

In addition to the information required by §98.3(g), 

you must retain the records specified in paragraphs (a) 

through (b) of this section for each hydrogen production 

facility. 
257

(a) If a CEMS is used to measure CO2 emissions, then 

you must retain under this subpart the records required for 

the Tier 4 Calculation Methodology in §98.37.

(b) If a CEMS is not used to measure CO2 emissions, 

then you must retain records of all analyses and 

calculations conducted as listed in §§98.166(b), (c), and 

(d).

§98.168 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part.

Subpart V—Nitric Acid Production

§98.220 Definition of Source Category.

A nitric acid production facility uses one or more 

trains to produce weak nitric acid (30 to 70 percent in 

strength). A nitric acid train produces weak nitric acid 

through the catalytic oxidation of ammonia.

§98.221 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a nitric acid train and the facility 

meets the requirements of either §98.2(a)(1) or (a)(2).

§98.222 GHGs to report.

(a) You must report N2O process emissions from each 

nitric acid production train as required by this subpart.
258

(b) You must report under subpart C of this part 

(General Stationary Fuel Combustion Sources) the emissions 

of CO2, CH4, and N2O from each stationary combustion unit by 

following the requirements of subpart C.

§98.223 Calculating GHG emissions. 

(a) You must determine annual N2O process emissions 

from each nitric acid train according to paragraphs (a)(1) 

or (a)(2) of this section.

(1) Use a site-specific emission factor and 

production data according to paragraphs (b) through (h) of 

this section.

(2) Request Administrator approval for an alternative 

method of determining N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section.

(i) You must submit the request within 45 days 

following promulgation of this subpart or within the first 

30 days of each subsequent reporting year.

(ii) If the Administrator does not approve your 

requested alternative method within 150 days of the end of 

the reporting year, you must determine the N2O emissions 

factor for the current reporting period using the 

procedures specified in paragraph (a)(1) of this section. 
259

(b) You must conduct an annual performance test 

according to paragraphs (b)(1) through (b)(3) of this 

section.

(1) You must measure N2O emissions from the absorber 

tail gas vent for each nitric acid train using the methods 

specified in §98.224(b) through (d).

(2) You must conduct the performance test under 

normal process operating conditions and without using N2O 

abatement technology (if applicable).

(3) You must measure the production rate during the 

performance test and calculate the production rate for the 

test period in metric tons (100 percent acid basis) per 

hour.

(c) You must determine an N2O emissions factor to use 

in Equation V-3 of this section according to paragraphs 

(c)(1) or (c)(2) of this section. 

(1) You may request Administrator approval for an 

alternative method of determining N2O concentration 

according to the procedures in paragraphs (a)(2)(i) and 

(a)(2)(ii) of this section. Alternative methods include 

the use of N2O CEMs. 

(2) Using the results of the performance test in 

paragraph (b) of this section, you must calculate an 
260

average site-specific emission factor for each nitric acid 

train “t” according to Equation V-1 of this section:

n

P

C Q

EF

n

N O

N Ot



  





1

7

2

2

1.14 10

(Eq. V-1)

Where: 

EFN2Ot = Average site-specific N2O emissions factor for 

nitric acid train “t” (lb N2O generated/ton 

nitric acid produced, 100 percent acid basis).

CN2O = N2O concentration for each test run during the 

performance test (ppm N2O).

1.14x10-7= Conversion factor (lb/dscf-ppm N2O).

Q = Volumetric flow rate of effluent gas for each 

test run during the performance test (dscf/hr).

P = Production rate for each test run during the 

performance test (tons nitric acid produced per 

hour, 100 percent acid basis).

n = Number of test runs.

(d) If applicable, you must determine the destruction 

efficiency for each N2O abatement technology according to 

paragraphs (d)(1), (d)(2), or (d)(3) of this section.

(1) Use the manufacturer’s specified destruction 

efficiency.

(2) Estimate the destruction efficiency through 

process knowledge. Examples of information that could 

constitute process knowledge include calculations based on 

material balances, process stoichiometry, or previous test 

results provided the results are still relevant to the 

current vent stream conditions. You must document how 
261

process knowledge (if applicable) was used to determine the 

destruction efficiency.

(3) Calculate the destruction efficiency by 

conducting an additional performance test on the emissions 

stream following the N2O abatement technology.

(e) If applicable, you must determine the abatement 

factor for each N2O abatement technology. The abatement 

factor is calculated for each nitric acid train according 

to Equation V-2 of this section.

a t

a t Abate

N t

P

P

AF  (Eq. V-2)

Where:

AFN t = Abatement factor of N2O abatement technology 

at nitric acid train “t” (fraction of annual 

production that abatement technology is 

operating).

Pa t = Total annual nitric acid production from 

nitric acid train “t” (ton acid produced, 

100 percent acid basis).

Pa t Abate = Annual nitric acid production from 

nitric acid train “t” during which N2O 

abatement was used (ton acid produced, 100 

percent acid basis).

(f) You must determine the annual amount of nitric 

acid produced and the annual amount of nitric acid produced 

while each N2O abatement technology is operating from each 

nitric acid train (100 percent basis). 

(g) You must calculate N2O emissions for each nitric 

acid train by multiplying the emissions factor (determined 
262

in Equation V-1 of this section) by the annual nitric acid 

production and accounting for N2O abatement, according to 

Equation V-3 of this section: 







z

N

N t a t N t N t

N Ot

EF P DF AF

E

1

20

2204.63

* *(1 ( * ))

2

(Eq. V-3)

Where:

EN2Ot = N2O mass emissions per year for nitric acid 

train “t” (metric tons).

EFN2Ot = Average site-specific N2O emissions factor 

for nitric acid train ”t” (lb N2O 

generated/ton acid produced, 100 percent 

acid basis).

Pa t = Annual nitric acid production from the train 

“t” (ton acid produced, 100 percent acid 

basis).

DFN t = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid 

train “t” (percent of N2O removed from air 

stream).

AFN t = Abatement factor of N2O abatement technology 

for nitric acid train “t” (fraction of 

annual production that abatement technology 

is operating).

2204.63 = Conversion factor (lb/metric ton).

z = Number of different N2O abatement 

technologies.

(h) You must determine the annual nitric acid 

production emissions combined from all nitric acid trains 

at your facility using Equation V-4 of this section:





m

t

N O EN Ot

1

2 2 (Eq. V-4)

Where:

N2O = Annual process N2O emissions from nitric 

acid production facility (metric tons)
263

EN2Ot = N2O mass emissions per year for nitric acid 

train “t” (metric tons).

m = Number of nitric acid trains.

§98.224 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test and 

calculate a new site-specific emissions factor according to 

a test plan as specified in paragraphs (a)(1) through 

(a)(3) of this section.

(1) Conduct the performance test annually.

(2) Conduct the performance test when your nitric 

acid production process is changed, specifically when 

abatement equipment is installed. 

(3) If you requested Administrator approval for an 

alternative method of determining N2O concentration under 

§98.223(a)(2), you must conduct the performance test if 

your request has not been approved by the Administrator 

within 150 days of the end of the reporting year in which 

it was submitted. 

(b) You must measure the N2O concentration during the 

performance test using one of the methods in paragraphs 

(b)(1) through (b)(3) of this section.

(1) EPA Method 320 at 40 CFR part 63, appendix A, 

Measurement of Vapor Phase Organic and Inorganic Emissions 
264

by Extractive Fourier Transform Infrared (FTIR) 

Spectroscopy.

(2) ASTM D6348-03 Standard Test Method for 

Determination of Gaseous Compounds by Extractive Direct 

Interface Fourier Transform Infrared (FTIR) Spectroscopy 

(incorporated by reference in §98.7).

(3) An equivalent method, with Administrator 

approval.

(c) You must determine the production rate(s) (100 

percent basis) from each nitric acid train during the 

performance test according to paragraphs (c)(1) or (c)(2) 

of this section.

(1) Direct measurement of production and 

concentration (such as using flow meters, weigh scales, for 

production and concentration measurements). 

(2) Existing plant procedures used for accounting 

purposes (i.e. dedicated tank-level and acid concentration 

measurements).

(d) You must conduct all performance tests in 

conjunction with the applicable EPA methods in 40 CFR part 

60, appendices A-1 through A-4. Conduct three emissions 

test runs of 1 hour each. All QA/QC procedures specified 

in the reference test methods and any associated 

performance specifications apply. For each test, the 
265

facility must prepare an emission factor determination 

report that must include the items in paragraphs (d)(1) 

through (d)(3) of this section.

(1) Analysis of samples, determination of emissions, 

and raw data.

(2) All information and data used to derive the 

emissions factor(s). 

(3) The production rate during each test and how it 

was determined.

(e) You must determine the monthly nitric acid 

production and the monthly nitric acid production during 

which N2O abatement technology is operating from each nitric 

acid train according to the methods in paragraphs (c)(1) or 

(c)(2) of this section. 

(f) You must determine the annual nitric acid 

production and the annual nitric acid production during 

which N2O abatement technology is operating for each train 

by summing the respective monthly nitric acid production 

quantities.

§98.225 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable, a substitute data value for the missing 
266

parameter shall be used in the calculations as specified in 

paragraphs (a) and (b) of this section. 

(a) For each missing value of nitric acid production, 

the substitute data shall be the best available estimate 

based on all available process data or data used for 

accounting purposes (such as sales records). 

(b) For missing values related to the performance 

test, including emission factors, production rate, and N2O 

concentration, you must conduct a new performance test 

according to the procedures in §98.224 (a) through (d).

§98.226 Data reporting requirements. 

In addition to the information required by §98.3(c), 

each annual report must contain the information specified 

in paragraphs (a) through (o) of this section for each 

nitric acid production train.

(a) Train identification number.

(b) Annual process N2O emissions from each nitric acid 

train (metric tons).

(c) Annual nitric acid production from each nitric 

acid train (tons, 100 percent acid basis).

(d) Annual nitric acid production from each nitric 

acid train during which N2O abatement technology is 

operating (ton acid produced, 100 percent acid basis)
267

(e) Annual nitric acid production from the nitric 

acid facility (tons, 100 percent acid basis).

(f) Number of nitric acid trains.

(g) Number of abatement technologies (if applicable).

(h) Abatement technologies used (if applicable). 

(i) Abatement technology destruction efficiency for 

each abatement technology (percent destruction).

(j) Abatement utilization factor for each abatement 

technology (fraction of annual production that abatement 

technology is operating).

(k) Type of nitric acid process used for each nitric 

acid train (low, medium, high, or dual pressure).

(l) Number of times in the reporting year that 

missing data procedures were followed to measure nitric 

acid production (months).

(m) If you conducted a performance test and 

calculated a site-specific emissions factor according to 

§98.223(a)(1), each annual report must also contain the 

information specified in paragraphs (m)(1) through (m)(7) 

of this section for each nitric acid production facility.

(1) Emission factor calculated for each nitric acid 

train (lb N2O/ ton nitric acid, 100 percent acid basis).

(2) Test method used for performance test.
268

(3) Production rate per test run during performance 

test (tons nitric acid produced/hr, 100 percent acid 

basis).

(4) N2O concentration per test run during performance 

test (ppm N2O).

(5) Volumetric flow rate per test run during 

performance test (dscf/hr).

(6) Number of test runs during performance test.

(7) Number of times in the reporting year that a 

performance test had to be repeated (number).

(n) If you requested Administrator approval for an 

alternative method of determining N2O concentration under 

§98.223(a)(2), each annual report must also contain the 

information specified in paragraphs (n)(1) through (n)(4) 

of this section for each nitric acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

§98.227 Records that must be retained. 

In addition to the information required by §98.3(g), 

you must retain the records specified in paragraphs (a) 

through (g) of this section for each nitric acid production 

facility:
269

(a) Records of significant changes to process.

(b) Documentation of how process knowledge was used 

to estimate abatement technology destruction efficiency (if 

applicable).

(c) Performance test reports.

(d) Number of operating hours in the calendar year 

for each nitric acid train (hours).

(e) Annual nitric acid permitted production capacity 

(tons).

(f) Measurements, records, and calculations used to 

determine reported parameters.

(g) Documentation of the procedures used to ensure 

the accuracy of the measurements of all reported 

parameters, including but not limited to, calibration of 

weighing equipment, flow meters, and other measurement 

devices. The estimated accuracy of measurements made with 

these devices must also be recorded, and the technical 

basis for these estimates must be provided.

§98.228 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Subpart X—Petrochemical Production

§98.240 Definition of the source category.
270

(a) The petrochemical production source category 

consists of all processes that produce acrylonitrile, 

carbon black, ethylene, ethylene dichloride, ethylene 

oxide, or methanol, except as specified in paragraphs (b) 

through (g) of this section. The source category includes 

processes that produce the petrochemical as an intermediate 

in the onsite production of other chemicals as well as 

processes that produce the petrochemical as an end product 

for sale or shipment offsite.

(b) A process that produces a petrochemical as a 

byproduct is not part of the petrochemical production 

source category.

(c) A facility that makes methanol, hydrogen, and/or 

ammonia from synthesis gas is part of the petrochemical 

source category if the annual mass of methanol produced 

exceeds the individual annual mass production levels of 

both hydrogen recovered as product and ammonia. The 

facility is part of subpart P of this part (Hydrogen 

Production) if the annual mass of hydrogen recovered as 

product exceeds the individual annual mass production 

levels of both methanol and ammonia. The facility is part 

of subpart G of this part (Ammonia Manufacturing) if the 

annual mass of ammonia produced exceeds the individual 
271

annual mass production levels of both hydrogen recovered as 

product and methanol.

(d) A direct chlorination process that is operated 

independently of an oxychlorination process to produce 

ethylene dichloride is not part of the petrochemical 

production source category.

(e) A process that produces bone black is not part of 

the petrochemical source category.

(f) A process that produces a petrochemical from biobased feedstock is not part of the petrochemical production 

source category. 

(g) A process that solely distills or recycles waste 

solvent that contains a petrochemical is not part of the 

petrochemical production source category.

§98.241 Reporting threshold. 

You must report GHG emissions under this subpart if 

your facility contains a petrochemical process as specified 

in §98.240, and the facility meets the requirements of 

either §98.2(a)(1) or (2).

§98.242 GHGs to report.

You must report the information in paragraphs (a) 

through (c) of this section:

(a) CO2 CH4, and N2O process emissions from each 

petrochemical process unit. Process emissions include CO2
272

generated by reaction in the process and by combustion of 

process off-gas in stationary combustion units and flares. 

(1) If you comply with §98.243(b) or (d), report 

under this subpart the calculated CO2, CH4, and N2O 

emissions for each stationary combustion source and flare 

that burns any amount of petrochemical process off-gas. If 

you comply with §98.243(b), also report under this subpart 

the measured CO2 emissions from process vents routed to 

stacks that are not associated with stationary combustion 

units.

(2) If you comply with §98.243(c), report under this 

subpart the calculated CO2 emissions for each petrochemical 

process unit.

(b) CO2, CH4, and N2O combustion emissions from 

stationary combustion units. 

(1) If you comply with §98.243(b) or (d), report 

these emissions from stationary combustion units that are 

associated with petrochemical process units and burn only 

supplemental fuel under subpart C of this part (General 

Stationary Fuel Combustion Sources) by following the 

requirements of subpart C.

(2) If you comply with §98.243(c), report CO2, CH4, 

and N2O combustion emissions under subpart C of this part 

(General Stationary Fuel Combustion Sources) by following 
273

the requirements of subpart C only for the combustion of 

supplemental fuel. Determine the applicable Tier in 

subpart C of this part (General Stationary Fuel Combustion 

Sources) based on the maximum rated heat input capacity of 

the stationary combustion source. 

(c) CO2 captured. You must report the mass of CO2

captured under, subpart PP of this part (Suppliers of 

Carbon Dioxide (CO2) by following the requirements of 

subpart PP. 

§98.243 Calculating GHG emissions.

(a) If you route all process vent emissions and 

emissions from combustion of process off-gas to one or more 

stacks and use CEMS on each stack to measure CO2 emissions 

(except flare stacks), then you must determine processbased GHG emissions in accordance with paragraph (b) of 

this section. Otherwise, determine process-based GHG 

emissions in accordance with the procedures specified in 

paragraph (c) or (d) of this section. 

(b) Continuous emission monitoring system (CEMS). 

Route all process vent emissions and emissions from 

combustion of process off-gas to one or more stacks and 

determine CO2 emissions from each stack (except flare 

stacks) according to the Tier 4 Calculation Methodology 

requirements in subpart C of this part. For each stack 
274

(except flare stacks) that includes emissions from 

combustion of petrochemical process off-gas, calculate CH4

and N20 emissions in accordance with subpart C of this part 

(use the Tier 3 methodology, emission factors for 

“Petroleum” in Table C-2 of subpart C of this part, and

either the default high heat value for fuel gas in Table C1 of subpart C of this part or a calculated HHV, as allowed 

in Equation C-8 of subpart C of this part). For each 

flare, calculate CO2, CH4, and N2O emissions using the 

methodology specified in §98.253(b)(1) through (b)(3). 

(c) Mass balance for each petrochemical process unit. 

Calculate the emissions of CO2 from each process unit, for 

each calendar month as described in paragraphs (c)(1) 

through (c)(5) of this section.

(1) For each gaseous and liquid feedstock and 

product, measure the volume or mass used or produced each 

calendar month with a flow meter by following the 

procedures specified in §98.244(b)(2). Alternatively, for 

liquids, you may calculate the volume used or collected in 

each month based on measurements of the liquid level in a 

storage tank at least once per month (and just prior to 

each change in direction of the level of the liquid) 

following the procedures specified in §98.244(b)(3). Fuels 
275

used for combustion purposes are not considered to be 

feedstocks.

(2) For each solid feedstock and product, measure the 

mass used or produced each calendar month by following the 

procedures specified in §98.244(b)(1).

(3) Collect a sample of each feedstock and product at 

least once per month and determine the carbon content of 

each sample according to the procedures in §98.244(b)(4). 

Alternatively, you may use the results of analyses 

conducted by a fuel or feedstock supplier, provided the 

sampling and analysis is conducted at least once per month 

using any of the procedures specified in §98.244(b)(4). If 

multiple valid carbon content measurements are made during 

the monthly measurement period, average them 

arithmetically.

(4) If you determine that the monthly average 

concentration of a specific compound in a feedstock or 

product is greater than 99.5 percent by volume (or mass for 

liquids and solids), then as an alternative to the sampling 

and analysis specified in paragraph (c)(3) of this section, 

you may calculate the carbon content assuming 100 percent 

of that feedstock or product is the specific compound 

during periods of normal operation. You must maintain 

records of any determination made in accordance with this 
276

paragraph (c)(4) along with all supporting data, 

calculations, and other information. This alternative may 

not be used for products during periods of operation when 

off-specification product is produced. You must reevaluate 

determinations made under this paragraph (c)(4) after any 

process change that affects the feedstock or product 

composition. You must keep records of the process change 

and the corresponding composition determinations. If the 

feedstock or product composition changes so that the 

average monthly concentration falls below 99.5 percent, you 

are no longer permitted to use this alternative method.

(5) Calculate the CO2 mass emissions for each 

petrochemical process unit using Equations X-1 through X-4 

of this section.

(i) Gaseous feedstocks and products. Use Equation X1 of this section to calculate the net annual carbon input 

or output from gaseous feedstocks and products. Note that 

the result will be a negative value if there are no gaseous 

feedstocks in the process but there are gaseous products.

        ]]

( )

* *

( )

[ [ * * ,

,

, ,

12

1 1 MVC

MW

P CC

MVC

MW

C F CC p i

i n

gp

i n

gp

f i

i n

gf i ngf

n

j or k

i

g    

 

(Eq. X-1)

Where: 

Cg = Annual net contribution to calculated emissions 

from carbon (C) in gaseous materials 

(kilograms/year, kg/yr).

(Fgf)i,n = Volume of gaseous feedstock i introduced in 

month “n” (standard cubic feet, scf).
277

(CCgf)i,n = Average carbon content of the gaseous feedstock 

i for month “n” (kg C per kg of feedstock).

(MWf)i = Molecular weight of gaseous feedstock i (kg/kgmole).

MVC = Molar volume conversion factor (849.5 scf per 

kg-mole at 68 °F and 14.7 pounds per square 

inch absolute or 836.6 scf/kg-mole at 60 °F and 

14.7 pounds per square inch absolute).

(Pgp)i,n = Volume of gaseous product i produced in month 

“n” (scf).

(CCgp)i,n = Average carbon content of gaseous product i, 

including streams containing CO2 recovered for 

sale or use in another process, for month “n” 

(kg C per kg of product).

(MWp)i = Molecular weight of gaseous product i (kg/kgmole).

j = Number of feedstocks.

k = Number of products.

(ii) Liquid feedstocks and products. Use Equation X2 of this section to calculate the net carbon input or 

output from liquid feedstocks and products. Note that the 

result will be a negative value if there are no liquid 

feedstocks in the process but there are liquid products.

[ [  *     *   ]]

,

,

, ,

12

1 1

i n

lp

i n

i n lp lf i n

lf

n

j or k

i

C l    F CC  P CC

 

(Eq. X-2)

Where:

Cl = Annual net contribution to calculated emissions 

from carbon in liquid materials, including 

liquid organic wastes (kg/yr).

(Flf)i,n = Volume or mass of liquid feedstock i introduced 

in month “n” (gallons or kg).

(CClf)i,n = Average carbon content of liquid feedstock i 

for month “n” (kg C per gallon or kg of 

feedstock).

(Plp)i,n = Volume or mass of liquid product i produced in 

month “n” (gallons or kg).
278

(CClp)i,n = Average carbon content of liquid product i, 

including organic liquid wastes, for month “n” 

(kg C per gallon or kg of product).

j = Number of feedstocks.

k = Number of products.

(iii) Solid feedstocks and products. Use Equation X3 of this section to calculate the net annual carbon input 

or output from solid feedstocks and products. Note that 

the result will be a negative value if there are no solid 

feedstocks in the process but there are solid products.

           

  











 

12

1

, , , ,

1

* *

n

i n

sp i nsp i nsf i nsf

j or k

i

C s F CC P CC (Eq. X-3)

Where:

Cs = Annual net contribution to calculated emissions 

from carbon in solid materials (kg/yr).

(Fsf)i,n = Mass of solid feedstock i introduced in month 

“n” (kg).

(CCsf)i,n= Average carbon content of solid feedstock i for 

month “n” (kg C per kg of feedstock).

(Psp)i,n = Mass of solid product i produced in month “n” 

(kg).

(CCsp)i,n = Average carbon content of solid product i in 

month “n” (kg C per kg of product).

j = Number of feedstocks.

k = Number of products.

(iv) Annual emissions. Use the results from 

Equations X-1 through X-3 of this section, as applicable, 

in Equation X-4 of this section to calculate annual CO2

emissions.

  CO  C g  Cl  C s

*

12

44 0.001 * 2

(Eq. X-4)
279

Where: 

CO2 = Annual CO2 mass emissions from process 

operations and process off-gas combustion 

(metric tons/year).

0.001 = Conversion factor from kg to metric tons.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of carbon (C) (kg/kg-mole).

(d) Optional combustion methodology for ethylene 

production processes. For each ethylene production 

process, calculate GHG emissions from each combustion unit 

that burns fuel that contains any off-gas from the ethylene 

process as specified in paragraphs (d)(1) through (d)(5) of 

this section. 

(1) Except as specified in paragraphs (d)(2) and 

(d)(5) of this section, calculate CO2 emissions using the

Tier 3 or Tier 4 methodology in subpart C of this part.

(2) You may use either Equation C-1 or Equation C-2a 

in subpart C of this part to calculate CO2 emissions from 

combustion of any ethylene process off-gas streams that 

meet either of the conditions in paragraphs (d)(2)(i) or 

(d)(2)(ii) of this section (for any default values in the 

calculation, use the defaults for fuel gas in Table C-1 of 

subpart C of this part). Follow the otherwise applicable 

procedures in subpart C to calculate emissions from 

combustion of all other fuels in the combustion unit.
280

(i) The annual average flow rate of fuel gas (that 

contains ethylene process off-gas) in the fuel gas line to 

the combustion unit, prior to any split to individual 

burners or ports, does not exceed 345 standard cubic feet 

per minute at 60°F and 14.7 pounds per square inch 

absolute, and a flow meter is not installed at any point in 

the line supplying fuel gas or an upstream common pipe.

Calculate the annual average flow rate using company 

records assuming total flow is evenly distributed over 

525,600 minutes per year.

(ii) The combustion unit has a maximum rated heat 

input capacity of less than 30 MMBtu/hr, and a flow meter

is not installed at any point in the line supplying fuel 

gas (that contains ethylene process off-gas) or an upstream 

common pipe.

(3) Except as specified in paragraph (d)(5) of this 

section, calculate CH4 and N2O emissions using the 

applicable procedures in §98.33(c) for the same tier 

methodology that you used for calculating CO2 emissions.

(i) For all gaseous fuels that contain ethylene 

process off-gas, use the emission factors for “Petroleum” 

in Table C-2 of subpart C of this part (General Stationary 

Fuel Combustion Sources).
281

(ii) For Tier 3, use either the default high heat 

value for fuel gas in Table C-1 of subpart C of this part 

or a calculated HHV, as allowed in Equation C-8 of subpart 

C of this part. 

(4) You are not required to use the same Tier for 

each stationary combustion unit that burns ethylene process 

off-gas. 

(5) For each flare, calculate CO2, CH4, and N2O 

emissions using the methodology specified in §98.253(b)(1) 

through (b)(3).

§98.244 Monitoring and QA/QC requirements.

(a) If you use CEMS to determine emissions from 

process vents, you must comply with the procedures 

specified in §98.34(c).

(b) If you use the mass balance methodology in 

§98.243(c), use the procedures specified in paragraphs 

(b)(1) through (b)(4) of this section to determine 

feedstock and product flows and carbon contents.

(1) Operate, maintain, and calibrate belt scales or 

other weighing devices as described in Specifications, 

Tolerances, and Other Technical Requirements For Weighing 

and Measuring Devices NIST Handbook 44 (2009) (incorporated 

by reference, see §98.7) or follow procedures specified by 

the measurement device manufacturer. You must recalibrate
282

each weighing device at one of the following frequencies. 

You may recalibrate either biennially (i.e., once every two 

years) or at the minimum frequency specified by the 

manufacturer.

(2) Operate and maintain all flow meters used for gas 

and liquid feedstocks and products according to the 

manufacturer’s recommended procedures. You must calibrate 

each of these flow meters according to one of the 

following. You may use either an industry consensus

standard method or methods specified by the flow meter 

manufacturer. Each flow meter must meet the applicable 

accuracy specification in §98.3(i), except as otherwise 

specified in §98.3(i)(4) through (i)(6). You must 

recalibrate each flow meter according to one of the 

following frequencies. You may recalibrate either

biennially, at the minimum frequency specified by the 

manufacturer, or at the interval specified by the industry 

consensus standard practice used.

(3) You must perform tank level measurements (if used 

to determine feedstock or product flows) according to one 

of the following methods. You may use any standard method 

published by a consensus-based standards organization 

(e.g., ASTM, API, etc.) or you may use industry standard 

practice.
283

(4) Use any applicable methods specified in 

paragraphs (b)(4)(i) through (b)(4)(xiii) of this section

to determine the carbon content or composition of 

feedstocks and products and the average molecular weight of 

gaseous feedstocks and products. Calibrate instruments in 

accordance with paragraphs (b)(4)(i) through (b)(4)(xiii), 

as applicable. For coal used as a feedstock, the samples 

for carbon content determinations shall be taken at a 

location that is representative of the coal feedstock used 

during the corresponding monthly period. For carbon black 

products, samples shall be taken of each grade or type of 

product produced during the monthly period. Samples of 

coal feedstock or carbon black product for carbon content 

determinations may be either grab samples collected and 

analyzed monthly or a composite of samples collected more

frequently and analyzed monthly. Analyses conducted in 

accordance with methods specified in paragraphs (b)(4)(i) 

through (b)(4)(xiii) of this section may be performed by 

the owner or operator, by an independent laboratory, or by 

the supplier of a feedstock.

(i) ASTM D1945-03, Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7).
284

(ii) ASTM D6060-96 (Reapproved 2001) Standard 

Practice for Sampling of Process Vents With a Portable Gas 

Chromatograph (incorporated by reference, see §98.7).

(iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test 

Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide 

in High-Purity Ethylene by Gas Chromatography (incorporated 

by reference, see §98.7).

(iv) ASTM UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7).

(v) ASTM D3176-89 (Reapproved 2002) Standard Practice 

Method for Ultimate Analysis of Coal and Coke (incorporated 

by reference, see §98.7).

(vi) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7).

(vii) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7).

(viii) Methods 8031, 8021, or 8015 in “Test Methods 

for Evaluating Solid Waste, Physical/Chemical Methods,” EPA 

Publication No. SW-846, Third Edition, September 1986, as 

amended by Update I, November 15, 1992.
285

(ix) Method 18 at 40 CFR part 60, appendix A-6. 

(x) Performance Specification 9 in 40 CFR part 60, 

appendix B for continuous online gas analyzers. The 7-day 

calibration error test period must be completed prior to 

the effective date of the rule.

(xi) ASTM D2593-93 (Reapproved 2009) Standard Test 

Method for Butadiene Purity and Hydrocarbon Impurities by 

Gas Chromatography, (incorporated by reference, see §98.7), 

effective as of January 1, 2010. 

(xii) An industry standard practice for carbon black 

feedstock oils and carbon black products, effective as of 

January 1, 2010.

(xiii) Modifications of existing analytical methods 

or other analytical methods that are applicable to your 

process provided that the methods listed in 

§98.244(b)(4)(i) through §98.244(b)(4)(xii) are not 

appropriate because the relevant compounds cannot be 

detected, the quality control requirements are not 

technically feasible, or use of the method would be unsafe, 

effective as of January 1, 2010.

§98.245 Procedures for estimating missing data.

For missing feedstock flow rates, product flow rates, 

and carbon contents, use the same procedures as for missing 
286

flow rates and carbon contents for fuels as specified in 

§98.35.

§98.246 Data reporting requirements.

In addition to the information required by §98.3(c), 

each annual report must contain the information specified 

in paragraphs (a), (b), or (c) of this section, as 

appropriate for each process unit.

(a) If you use the mass balance methodology in 

§98.243(c), you must report the information specified in 

paragraphs (a)(1) through (a)(11) of this section for each 

type of petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other 

appropriate descriptor.

(2) The type of petrochemical produced, names of 

other products, and names of carbon-containing feedstocks.

(3) Annual CO2 emissions calculated using Equation X-4 

of this subpart.

(4) Each of the monthly volume, mass, and carbon 

content values used in Equations X-1 through X-3 of this 

subpart (i.e., the directly measured values, substitute 

values, or the calculated values based on other measured 

data such as tank levels or gas composition) and the 

molecular weights for gaseous feedstocks and products used 

in Equation X-1 of this subpart, and the temperture (in °F) 
287

at which the gaseous feedstock and product volumes used in 

Equation X-1 of this subpart were determined. Indicate 

whether you used the alternative to sampling and analysis 

specified in §98.243(c)(4).

(5) Annual quantity of each type of petrochemical 

produced from each process unit (metric tons).

(6) Name of each method listed in §98.244 used to 

determine a measured parameter (or description of 

manufacturer’s recommended method).

(7) [Reserved]

(8) Identification of each combustion unit that 

burned both process off-gas and supplemental fuel.

(9) If you comply with the alternative to sampling 

and analysis specified in §98.243(c)(4), the amount of time 

during which off-specification product was produced, the 

volume or mass of off-specification product produced, and 

if applicable, the date of any process change that reduced 

the composition to less than 99.5 percent.

(10) You may elect to report the flow and carbon 

content of wastewater, and you may elect to report the 

annual mass of carbon released in fugitive emissions and in 

process vents that are not controlled with a combustion 

device. These values may be estimated based on engineering 
288

analyses. These values are not to be used in the mass 

balance calculation.

(11) If you determine carbon content or composition 

of a feedstock or product using a method under 

§98.244(b)(4)(xiii), report the information listed in 

paragraphs (a)(11)(i) through (a)(11)(iii) of this section. 

Include the information in paragraph (a)(11)(i) of this 

section in each annual report. Include the information in 

paragraphs (a)(11)(ii) and (a)(11)(iii) of this section 

only in the first applicable annual report, and provide any 

changes to this information in subsequent annual reports.

(i) Name or title of the analytical method.

(ii) A copy of the method. If the method is a 

modification of a method listed in §98.244(b)(4)(i) through 

(xii), you may provide a copy of only the sections that 

differ from the listed method.

(iii) An explanation of why an alternative to the 

methods listed in §98.244(b)(4)(i) through (xii) is needed.

(b) If you measure emissions in accordance with 

§98.243(b), then you must report the information listed in 

paragraphs (b)(1) through (b)(8) of this section.

(1) The petrochemical process unit ID or other 

appropriate descriptor, and the type of petrochemical 

produced.
289

(2) For CEMS used on stacks for stationary combustion 

units, report the relevant information required under 

§98.36 for the Tier 4 calculation methodology. Section 

98.36(b)(9)(iii) does not apply for the purposes of this 

subpart.

(3) For CEMS used on stacks that are not used for 

stationary combustion units, report the information 

required under §98.36(e)(2)(vi).

(4) The CO2 emissions from each stack and the combined 

CO2 emissions from all stacks (except flare stacks) that 

handle process vent emissions and emissions from stationary 

combustion units that burn process off-gas for the 

petrochemical process unit. For each stationary combustion 

unit (or group of combustion units monitored with a single 

CO2 CEMS) that burns petrochemical process off-gas, provide 

an estimate based on engineering judgment of the fraction 

of the total emissions that is attributable to combustion 

of off-gas from the petrochemical process unit.

(5) For stationary combustion units that burn process 

off-gas from the petrochemical process unit, report the 

information related to CH4 and N2O emissions as specified in 

paragraphs (b)(5)(i) through (b)(5)(iv) of this section.

(i) The CH4 and N2O emissions from each stack that is 

monitored with a CO2 CEMS, expressed in metric tons of each 
290

gas and in metric tons of CO2e. For each stack provide an 

estimate based on engineering judgment of the fraction of 

the total emissions that is attributable to combustion of 

off-gas from the petrochemical process unit.

(ii) The combined CH4 and N2O emissions from all 

stationary combustion units, expressed in metric tons of 

each gas and in metric tons of CO2e.

(iii) The quantity of each type of fuel used in 

Equation C-8 in §98.33(c) for each stationary combustion 

unit or group of units (as applicable) during the reporting 

year, expressed in short tons for solid fuels, gallons for 

liquid fuels, and scf for gaseous fuels.

(iv) The HHV (either default or annual average from 

measured data) used in Equation C-8 in §98.33(c) for each 

stationary combustion unit or group of combustion units (as 

applicable).

(6) ID or other appropriate descriptor of each 

stationary combustion unit that burns process off-gas.

(7) Information listed in §98.256(e) of subpart Y of 

this part for each flare that burns process off-gas.

(8) Annual quantity of each type of petrochemical 

produced from each process unit (metric tons).

(c) If you comply with the combustion methodology 

specified in §98.243(d), you must report under this subpart 
291

the information listed in paragraphs (c)(1) through (c)(5) 

of this section.

(1) The ethylene process unit ID or other appropriate 

descriptor. 

(2) For each stationary combustion unit that burns 

ethylene process off-gas (or group of stationary sources 

with a common pipe), except flares, the relevant 

information listed in §98.36 for the applicable Tier 

methodology. For each stationary combustion unit or group 

of units (as applicable) that burns ethylene process offgas, provide an estimate based on engineering judgment of 

the fraction of the total emissions that is attributable to 

combustion of off-gas from the ethylene process unit.

(3) Information listed in §98.256(e) of subpart Y of 

this part for each flare that burns ethylene process offgas.

(4) Name and annual quantity of each feedstock.

(5) Annual quantity of ethylene produced from each 

process unit (metric tons).

§98.247 Records that must be retained.

In addition to the recordkeeping requirements in 

§98.3(g), you must retain the records specified in 

paragraphs (a) through (c) of this section, as applicable.
292

(a) If you comply with the CEMS measurement 

methodology in §98.243(b), then you must retain under this 

subpart the records required for the Tier 4 Calculation 

Methodology in §98.37, records of the procedures used to 

develop estimates of the fraction of total emissions 

attributable to combustion of petrochemical process off-gas 

as required in §98.246(b), and records of any annual 

average HHV calculations.

(b) If you comply with the mass balance methodology 

in §98.243(c), then you must retain records of the 

information listed in paragraphs (b)(1) through (b)(4) of 

this section.

(1) Results of feedstock or product composition 

determinations conducted in accordance with §98.243(c)(4).

(2) Start and end times and calculated carbon 

contents for time periods when off-specification product is 

produced, if you comply with the alternative methodology in 

§98.243(c)(4) for determining carbon content of feedstock 

or product.

(3) A part of the monitoring plan required under 

§98.3(g)(5), record the estimated accuracy of measurement 

devices and the technical basis for these estimates.

(4) The dates and results (e.g., percent calibration 

error) of the calibrations of each measurement device.
293

(c) If you comply with the combustion methodology in 

§98.243(d), then you must retain under this subpart the 

records required for the applicable Tier Calculation 

Methodologies in §98.37. If you comply with §98.243(d)(2), 

you must also keep records of the annual average flow 

calculations.

§98.248 Definitions.

Except as specified in this section, all terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. 

Product, as used in §98.243, means each of the 

following carbon-containing outputs from a process: the 

petrochemical, recovered byproducts, and liquid organic 

wastes that are not incinerated onsite. Product does not 

include process vent emissions, fugitive emissions, or 

wastewater.

Subpart Y—Petroleum Refineries

§98.250 Definition of Source Category.

(a) A petroleum refinery is any facility engaged in 

producing gasoline, gasoline blending stocks, naphtha, 

kerosene, distillate fuel oils, residual fuel oils, 

lubricants, or asphalt (bitumen) through distillation of 

petroleum or through redistillation, cracking, or reforming 
294

of unfinished petroleum derivatives, except as provided in 

paragraph (b) of this section.

(b) For the purposes of this subpart, facilities that 

distill only pipeline transmix (off-spec material created 

when different specification products mix during pipeline 

transportation) are not petroleum refineries, regardless of 

the products produced.

(c) This source category consists of the following 

sources at petroleum refineries: catalytic cracking units; 

fluid coking units; delayed coking units; catalytic 

reforming units; coke calcining units; asphalt blowing 

operations; blowdown systems; storage tanks; process 

equipment components (compressors, pumps, valves, pressure 

relief devices, flanges, and connectors) in gas service; 

marine vessel, barge, tanker truck, and similar loading 

operations; flares; sulfur recovery plants; and nonmerchant hydrogen plants (i.e., hydrogen plants that are 

owned or under the direct control of the refinery owner and 

operator).

§98.251 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a petroleum refineries process and 

the facility meets the requirements of either §98.2(a)(1) 

or (a)(2).
295

§98.252 GHGs to report.

You must report:

(a) CO2, CH4, and N2O combustion emissions from

stationary combustion units and from each flare. Calculate 

and report the emissions from stationary combustion units 

under subpart C of this part (General Stationary Fuel 

Combustion Sources) by following the requirements of 

subpart C, except for emissions from combustion of fuel 

gas. For CO2 emissions from combustion of fuel gas, use 

either Equation C-5 in subpart C of this part or the Tier 4 

methodology in subpart C of this part, unless either of the 

conditions in paragraphs (a)(1) or (2) of this section are 

met, in which case use either Equations C-1 or C-2a in 

subpart C of this part. For CH4 and N2O emissions from 

combustion of fuel gas, use the applicable procedures in 

§98.33(c) for the same tier methodology that was used for 

calculating CO2 emissions. (Use the default CH4 and N2O 

emission factors for “Petroleum (All fuel types in Table C1)” in Table C-2 of this part. For Tier 3, use either the 

default high heat value for fuel gas in Table C-1 of 

subpart C of this part or a calculated HHV, as allowed in 

Equation C-8 of subpart C of this part.) You may aggregate 

units, monitor common stacks, or monitor common (fuel) 

pipes as provided in §98.36(c) when calculating and 
296

reporting emissions from stationary combustion units. 

Calculate and report the emissions from flares under this 

subpart.

(1) The annual average fuel gas flow rate in the fuel 

gas line to the combustion unit, prior to any split to 

individual burners or ports, does not exceed 345 standard 

cubic feet per minute at 60oF and 14.7 pounds per square 

inch absolute and either of the conditions in paragraph 

(a)(1)(i) or (ii) of this section exist. Calculate the 

annual average flow rate using company records assuming 

total flow is evenly distributed over 525,600 minutes per 

year.

(i) A flow meter is not installed at any point in the 

line supplying fuel gas or an upstream common pipe.

(ii) The fuel gas line contains only vapors from 

loading or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a thermal 

oxidizer or thermal incinerator.

(2) The combustion unit has a maximum rated heat 

input capacity of less than 30 MMBtu/hr and either of the 

following conditions exist:

(i) A flow meter is not installed at any point in the 

line supplying fuel gas or an upsteam common pipe; or
297

(ii) The fuel gas line contains only vapors from 

loading or unloading, waste or wastewater handling, and 

remediation activities that are combusted in a thermal 

oxidizer or thermal incinerator.(b) CO2, CH4, and N2O coke

burn-off emissions from each catalytic cracking unit, fluid 

coking unit, and catalytic reforming unit under this 

subpart.

(c) CO2 emissions from sour gas sent off site for 

sulfur recovery operations under this subpart. You must 

follow the calculation methodologies from §98.253(f)and the 

monitoring and QA/QC methods, missing data procedures, 

reporting requirements, and recordkeeping requirements of 

this subpart.

(d) CO2 process emissions from each on-site sulfur 

recovery plant under this subpart.

(e) CO2, CH4, and N2O emissions from each coke 

calcining unit under this subpart. 

(f) CO2 and CH4 emissions from asphalt blowing 

operations under this subpart. 

(g) CH4 emissions from equipment leaks, storage tanks, 

loading operations, delayed coking units, and uncontrolled 

blowdown systems under this subpart.
298

(h) CO2, CH4, and N2O emissions from each process vent 

not specifically included in paragraphs (a) through (g) of 

this section under this subpart.

(i) CO2 emissions from non-merchant hydrogen 

production process units (not including hydrogen produced 

from catalytic reforming units) under this subpart. You 

must follow the calculation methodologies, monitoring and 

QA/QC methods, missing data procedures, reporting 

requirements, and recordkeeping requirements of subpart P 

of this part. 

§98.253 Calculating GHG emissions.

(a) Calculate GHG emissions required to be reported 

in §98.252(b) through (i) using the applicable methods in 

paragraphs (b) through (n) of this section. 

(b) For flares, calculate GHG emissions according to 

the requirements in paragraphs (b)(1) through (b)(3) of 

this section.

(1) Calculate the CO2 emissions according to the 

applicable requirements in paragraphs (b)(1)(i) through 

(b)(1)(iii) of this section.

(i) Flow measurement. If you have a continuous flow 

monitor on the flare, you must use the measured flow rates 

when the monitor is operational and the flow rate is within 

the calibrated range of the measurement device to calculate 
299

the flare gas flow. If you do not have a continuous flow 

monitor on the flare and for periods when the monitor is 

not operational or the flow rate is outside the calibrated 

range of the measurement device, you must use engineering 

calculations, company records, or similar estimates of 

volumetric flare gas flow.

(ii) Heat value or carbon content measurement. If 

you have a continuous higher heating value monitor or gas 

composition monitor on the flare or if you monitor these 

parameters at least weekly, you must use the measured heat 

value or carbon content value in calculating the CO2

emissions from the flare using the applicable methods in 

paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B). 

(A) If you monitor gas composition, calculate the CO2

emissions from the flare using either Equation Y-1a or 

Equation Y-1b of this section. If daily or more frequent 

measurement data are available, you must use daily values 

when using Equation Y-1a or Equation Y-1b of this section; 

otherwise, use weekly values.

 

 

 

































      



n

p

p

p

p CC

MVC

MW

CO Flare

1

2

12

44 0.98 0.001 (Eq.Y-1a)

Where: 
300

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, measure flare gas flow rate in kg/period 

and replace the term “(MW)p/MVC” with “1”.

(MW)p = Average molecular weight of the flare gas 

combusted during measurement period (kg/kgmole). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average.

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 pounds per square inch 

absolute (psia) or 836.6 scf/kg-mole at 60 oF 

and 14.7 psia).

(CC)p = Average carbon content of the flare gas 

combusted during measurement period (kg C per 

kg flare gas). If measurements are taken more 

frequently than daily, use the arithmetic 

average of measurement values within the day 

to calculate a daily average.

 

   

    











































      

n

p

y

x

x

p x p

p CMN

CO C

MVC

CO Flare

1 1

2

2

100%

%

0.98

100%

%

0.001 44

(Eq.Y-1b)

Where: 
301

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during 

measurement period (standard cubic feet per 

period, scf/period). If a mass flow meter is 

used, you must determine the average molecular 

weight of the flare gas during the measurement 

period and convert the mass flow to a 

volumetric flow.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68oF and 14.7 psia or 836.6 scf/kgmole at 60oF and 14.7 psia).

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

(%CO2)p = Mole percent CO2 concentration in the flare 

gas stream during the measurement period (mole 

percent = percent by volume). 

y = Number of carbon-containing compounds other 

than CO2 in the flare gas stream.

x = Index for carbon-containing compounds other 

than CO2.

0.98 = Assumed combustion efficiency of a flare (mole 

CO2 per mole carbon).

(%Cx)p = Mole percent concentration of compound “x” in 

the flare gas stream during the measurement 

period (mole percent = percent by volume) 

CMNx = Carbon mole number of compound “x” in the 

flare gas stream (mole carbon atoms per mole 

compound). E.g., CMN for ethane (C2H6) is 2; 

CMN for propane (C3H8) is 3. 

(B) If you monitor heat content but do not monitor 

gas composition, calculate the CO2 emissions from the flare 
302

using Equation Y-2 of this section. If daily or more 

frequent measurement data are available, you must use daily 

values when using Equation Y-2 of this section; otherwise, 

use weekly values.

    



    

n

p

CO Flare p HHV p EmF

1

2 0.98 0.001 (Eq.Y-2)

Where: 

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

n = Number of measurement periods. The minimum 

value for n is 52 (for weekly measurements); 

the maximum value for n is 366 (for daily 

measurements during a leap year).

p = Measurement period index.

(Flare)p = Volume of flare gas combusted during 

measurement period (million (MM) scf/period). 

If a mass flow meter is used, you must also 

measure molecular weight and convert the mass 

flow to a volumetric flow as follows: 

Flare[MMscf] = 0.000001 × Flare[kg] × 

MVC/(MW)p, where MVC is the molar volume 

conversion factor (849.5 scf/kg-mole) and 

(MW)p is the average molecular weight of the 

flare gas combusted during measurement period 

(kg/kg-mole). 

(HHV)p = Higher heating value for the flare gas 

combusted during measurement period (British 

thermal units per scf, Btu/scf = MMBtu/MMscf). 

If measurements are taken more frequently than 

daily, use the arithmetic average of 

measurement values within the day to calculate 

a daily average. 
303

EmF = Default CO2 emission factor of 60 kilograms 

CO2/MMBtu (HHV basis).

(iii) Alternative to heat value or carbon content 

measurements. If you do not measure the higher heating 

value or carbon content of the flare gas at least weekly, 

determine the quantity of gas discharged to the flare 

separately for periods of routine flare operation and for 

periods of start-up, shutdown, or malfunction, and 

calculate the CO2 emissions as specified in paragraphs 

(b)(1)(iii)(A) through (b)(1)(iii)(C) of this section.

(A) For periods of start-up, shutdown, or

malfunction, use engineering calculations and process 

knowledge to estimate the carbon content of the flared gas 

for each start-up, shutdown, or malfunction event exceeding 

500,000 scf/day. 

(B) For periods of normal operation, use the average 

heating value measured for the fuel gas for the heating 

value of the flare gas. If heating value is not measured, 

the heating value may be estimated from historic data or 

engineering calculations.

(C) Calculate the CO2 emissions using Equation Y-3 of 

this section.

 

 

 





























        



n

p

p

p

Norm SSM p CC

MVC

MW

CO Flare HHV EmF Flare

1

2

12

44 0.98 0.001

(Eq.Y-3)

Where: 
304

CO2 = Annual CO2 emissions for a specific fuel type 

(metric tons/year).

0.98 = Assumed combustion efficiency of a flare.

0.001 = Unit conversion factor (metric tons per 

kilogram, mt/kg).

FlareNorm = Annual volume of flare gas combusted during 

normal operations from company records, 

(million (MM) standard cubic feet per year, 

MMscf/year).

HHV = Higher heating value for fuel gas or flare gas 

from company records (British thermal units 

per scf, Btu/scf = MMBtu/MMscf). 

EmF = Default CO2 emission factor for flare gas of 

60 kilograms CO2/MMBtu (HHV basis).

n = Number of start-up, shutdown, and malfunction 

events during the reporting year exceeding 

500,000 scf/day.

p = Start-up, shutdown, and malfunction event 

index.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(FlareSSM)p = Volume of flare gas combusted during indexed 

start-up, shutdown, or malfunction event from 

engineering calculations, (scf/event).

(MW)p = Average molecular weight of the flare gas, 

from the analysis results or engineering 

calculations for the event (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kgmole at 60 oF and 14.7 psia).

(CC)p = Average carbon content of the flare gas, from 

analysis results or engineering calculations 

for the event (kg C per kg flare gas).

(2) Calculate CH4 using Equation Y-4 of this section. 

2 4

CH4

4 2

44

16

0.98

0.02

EmF

EmF CH CO CH   CO    f











 

(Eq. Y-4)
305

Where:

CH4 = Annual methane emissions from flared gas 

(metric tons CH4/year).

CO2 = Emission rate of CO2 from flared gas 

calculated in paragraph (b)(1) of this section 

(metric tons/year).

EmFCH4 = Default CH4 emission factor for 

“PetroleumProducts” from Table C-2 of subpart 

C of this part (General Stationary Fuel 

Combustion Sources) (kg CH4/MMBtu).

EmF = Default CO2 emission factor for flare gas of 

60 kg CO2/MMBtu (HHV basis). 

0.02/0.98 = correction factor for flare combustion 

efficiency.

16/44 = correction factor ratio of the molecular 

weight of CH4 to CO2

fCH4 = Weight fraction of carbon in the flare gas 

prior to combustion that is contributed by 

methane from measurement values or engineering 

calculations (kg C in methane in flare gas/kg 

C in flare gas); default is 0.4.

(3) Calculate N2O emissions using Equation Y-5 of this 

section. 













 

EmF

EmF N O CO N2O

2 2 (Eq. Y-5)

Where:

N2O = Annual nitrous oxide emissions from flared gas 

(metric tons N2O/year).

CO2 = Emission rate of CO2 from flared gas calculated in 

paragraph (b)(1) of this section (metric 

tons/year).

EmFN2O = Default N2O emission factor for 

“PetroleumProducts” from Table C-2 of subpart C 

of this part (General Stationary Fuel Combustion 

Sources)(kg N2O/MMBtu).
306

EmF = Default CO2 emission factor for flare gas of 60 kg 

CO2/MMBtu (HHV basis).

(c) For catalytic cracking units and traditional 

fluid coking units, calculate the GHG emissions using the 

applicable methods described in paragraphs (c)(1) through 

(c)(5) of this section.

(1) If you operate and maintain a CEMS that measures 

CO2 emissions according to subpart C of this part (General 

Stationary Fuel Combustion Sources), you must calculate and 

report CO2 emissions as provided in paragraphs (c)(1)(i) and 

(c)(1)(ii) of this section. Other catalytic cracking units 

and traditional fluid coking units must either install a 

CEMS that complies with the Tier 4 Calculation Methodology 

in subpart C of this part (General Stationary Combustion 

Souces), or follow the requirements of paragraphs (c)(2) or 

(3) of this section. 

(i) Calculate CO2 emissions by following the Tier 4 

Calculation Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of this 

part (General Stationary Fuel Combustion Sources).

(ii) For catalytic cracking units whose process 

emissions are discharged through a combined stack with 

other CO2 emissions (e.g., co-mingled with emissions from a 

CO boiler) you must also calculate the other CO2 emissions 

using the applicable methods for the applicable subpart 
307

(e.g., subpart C of this part in the case of a CO boiler). 

Calculate the process emissions from the catalytic cracking 

unit or fluid coking unit as the difference in the CO2 CEMS

emissions and the calculated emissions associated with the 

additional units discharging through the combined stack. 

(2) For catalytic cracking units and fluid coking 

units with rated capacities greater than 10,000 barrels per 

stream day (bbls/sd) that do not use a continuous CO2 CEMS 

for the final exhaust stack, you must continuously or no 

less frequently than hourly monitor the O2, CO2, and (if 

necessary) CO concentrations in the exhaust stack from the 

catalytic cracking unit regenerator or fluid coking unit 

burner prior to the combustion of other fossil fuels and 

calculate the CO2 emissions according to the requirements of 

paragraphs (c)(2)(i) through (c)(2)(iii) of this section:

(i) Calculate the CO2 emissions from each catalytic 

cracking unit and fluid coking unit using Equation Y-6 of 

this section.

 

 















 



 

n

p

p

r p MVC

CO CO

CO Q

1

2

2

0.001 44

100%

% %

(Eq. Y-6)

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion 
308

of other fossil fuels (dry standard cubic feet 

per hour, dscfh).

%CO2 = Hourly average percent CO2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis).

%CO = Hourly average percent CO concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). When 

there is no post-combustion device, assume %CO 

to be zero.

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

n = Number of hours in calendar year.

(ii) Either continuously monitor the volumetric flow 

rate of exhaust gas from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner prior to the 

combustion of other fossil fuels or calculate the 

volumetric flow rate of this exhaust gas stream using 

either Equation Y-7a or Equation Y-7b of this section.

 

100 % 2 % % 2

79 * (100 % ) *

CO CO O

Q O Q

Q

a oxy oxy

r

  

 



(Eq. Y-7a)

Where:

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion 

of other fossil fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 
309

coking unit burner, as determined from control 

room instrumentation (dscfh).

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator or 

fluid coking unit burner as determined from 

control room instrumentation (dscfh).

%O2 = Hourly average percent oxygen concentration in 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis).

%Ooxy = O2 concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based on 

oxygen purity specifications of the oxygen supply 

used for enrichment (percent by volume – dry 

basis).

%CO2 = Hourly average percent CO2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis).

%CO = Hourly average percent CO concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis). When no 

auxiliary fuel is burned and a continuous CO 

monitor is not required under 40 CFR part 63 

subpart UUU, assume %CO to be zero.

 

exhaust

a oxy oxy

r

N

Q N Q

Q

2,

2,

%

78.1*  (% ) *

 (Eq. Y-7b)

Where: 

Qr = Volumetric flow rate of exhaust gas from the 

fluid catalytic cracking unit regenerator or 

fluid coking unit burner prior to the combustion 

of other fossil fuels (dscfh).

Qa = Volumetric flow rate of air to the fluid 

catalytic cracking unit regenerator or fluid 

coking unit burner, as determined from control 

room instrumentation (dscfh).
310

Qoxy = Volumetric flow rate of oxygen enriched air to 

the fluid catalytic cracking unit regenerator or 

fluid coking unit burner as determined from 

control room instrumentation (dscfh).

%N2,oxy = N2 concentration in oxygen enriched gas stream 

inlet to the fluid catalytic cracking unit 

regenerator or fluid coking unit burner based on 

measured value or maximum N2 impurity 

specifications of the oxygen supply used for 

enrichment (percent by volume – dry basis).

%N2,exhaust = Hourly average percent N2 concentration in the 

exhaust gas stream from the fluid catalytic 

cracking unit regenerator or fluid coking unit 

burner (percent by volume – dry basis).

(iii) If you have a CO boiler that uses auxiliary 

fuels or combusts materials other than catalytic cracking 

unit or fluid coking unit exhaust gas, you must determine 

the CO2 emissions resulting from the combustion of these 

fuels or other materials following the requirements in 

subpart C and report those emissions by following the 

requirements of subpart C of this part.

(3) For catalytic cracking units and fluid coking 

units with rated capacities of 10,000 barrels per stream 

day (bbls/sd) or less that do not use a continuous CO2 CEMS 

for the final exhaust stack, comply with the requirements 

in paragraphs (c)(3)(i) of this section or paragraphs 

(c)(3)(ii) and (c)(3)(iii) of this section, as applicable.

(i) If you continuously or no less frequently than 

daily monitor the O2, CO2, and (if necessary) CO 

concentrations in the exhaust stack from the catalytic 
311

cracking unit regenerator or fluid coking unit burner prior 

to the combustion of other fossil fuels, you must calculate 

the CO2 emissions according to the requirements of 

paragraphs (c)(2)(i) through (c)(2)(iii) of this section, 

except that daily averages are allowed and the summation 

can be performed on a daily basis. 

(ii) If you do not monitor at least daily the O2, CO2, 

and (if necessary) CO concentrations in the exhaust stack 

from the catalytic cracking unit regenerator or fluid 

coking unit burner prior to the combustion of other fossil 

fuels, calculate the CO2 emissions from each catalytic 

cracking unit and fluid coking unit using Equation Y-8 of 

this section. 

 

12

44 0.001 CO2  Qunit  CBF  CC  (Eq. Y-8)

Where:

CO2 = Annual CO2 mass emissions (metric tons/year).

Qunit = Annual throughput of unit from company records 

(barrels (bbls) per year, bbl/yr).

CBF = Coke burn-off factor from engineering 

calculations (kg coke per barrel of feed); 

default for catalytic cracking units = 7.3; 

default for fluid coking units = 11. 

0.001 = Conversion factor (metric ton/kg).

CC = Carbon content of coke based on measurement or 

engineering estimate (kg C per kg coke); 

default = 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2

per kg C).
312

(iii) If you have a CO boiler that uses auxiliary 

fuels or combusts materials other than catalytic cracking 

unit or fluid coking unit exhaust gas, you must determine 

the CO2 emissions resulting from the combustion of these 

fuels or other materials following the requirements in 

subpart C of this part (General Stationary Fuel Combustion 

Sources) and report those emissions by following the 

requirements of subpart C of this part.

(4) Calculate CH4 emissions using either unit specific 

measurement data, a unit-specific emission factor based on 

a source test of the unit, or Equation Y-9 of this section.



















1

2

4 2

EmF

EmF CH CO * (Eq. Y-9)

Where:

CH4 = Annual methane emissions from coke burn-off 

(metric tons CH4/year).

CO2 = Emission rate of CO2 from coke burn-off calculated 

in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), 

(g)(1), or (g)(2) of this section, as applicable 

(metric tons/year).

EmF1 = Default CO2 emission factor for petroleum coke 

from Table C-1 of subpart C of this part (General 

Stationary Fuel Combustion Sources) (kg 

CO2/MMBtu).

EmF2 = Default CH4 emission factor for 

”PetroleumProducts” from Table C-2 of subpart C 

of this part (General Stationary Fuel Combustion 

Sources) (kg CH4/MMBtu).

(5) Calculate N2O emissions using either unit specific 

measurement data, a unit-specific emission factor based on 
313

a source test of the unit, or Equation Y-10 of this 

section.



















1

3

2 2

EmF

EmF N O CO * (Eq. Y-10)

Where:

N2O = Annual nitrous oxide emissions from coke burn-off 

(mt N2O/year).

CO2 = Emission rate of CO2 from coke burn-off calculated 

in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), 

(g)(1), or (g)(2) of this section, as applicable 

(metric tons/year).

EmF1 = Default CO2 emission factor for petroleum coke 

from Table C-1 of subpart C of this part (General 

Stationary Fuel Combustion Sources) (kg 

CO2/MMBtu).

EmF3 = Default N2O emission factor for 

”PetroleumProducts” from Table C-2 of subpart C 

of this part (kg N2O/MMBtu).

(d) For fluid coking units that use the flexicoking 

design, the GHG emissions from the resulting use of the low 

value fuel gas must be accounted for only once. Typically, 

these emissions will be accounted for using the methods

described in subpart C of this part (General Stationary 

Fuel Combustion Sources). Alternatively, you may use the 

methods in paragraph (c) of this section provided that you 

do not otherwise account for the subsequent combustion of 

this low value fuel gas.

(e) For catalytic reforming units, calculate the CO2

emissions using the applicable methods described in 
314

paragraphs (e)(1) through (e)(3) of this section and 

calculate the CH4 and N2O emissions using the methods 

described in paragraphs (c)(4) and (c)(5) of this section, 

respectively.

(1) If you operate and maintain a CEMS that measures 

CO2 emissions according to subpart C of this part (General 

Stationary Fuel Combustion Sources), you must calculate CO2

emissions as provided in paragraphs (c)(1)(i) and 

(c)(1)(ii) of this section. Other catalytic reforming 

units must either install a CEMS that complies with the 

Tier 4 Calculation Methodology in subpart C of this part, 

or follow the requirements of paragraph (e)(2) or (e)(3) of 

this section.

(2) If you continuously or no less frequently than 

daily monitor the O2, CO2, and (if necessary) CO 

concentrations in the exhaust stack from the catalytic 

reforming unit catalyst regenerator prior to the combustion 

of other fossil fuels, you must calculate the CO2 emissions 

according to the requirements of paragraphs (c)(2)(i) 

through (c)(2)(iii) of this section.

(3) Calculate CO2 emissions from the catalytic 

reforming unit catalyst regenerator using Equation Y-11 of 

this section.
315

  













   

n

Q n

CO CB CC

1

2 0.001

12

44

(Eq. Y-11)

Where:

CO2 = Annual CO2 emissions (metric tons/year). 

CBQ = Coke burn-off quantity per regeneration cycle or 

measurement period from engineering estimates 

(kg coke/cycle or kg coke/measurement period).

n = Number of regeneration cycles or measurement 

periods in the calendar year. 

CC = Carbon content of coke based on measurement or 

engineering estimate (kg C per kg coke); default 

= 0.94.

44/12 = Ratio of molecular weight of CO2 to C (kg CO2 per 

kg C).

0.001 = Conversion factor (metric ton/kg).

(f) For on-site sulfur recovery plants and for sour 

gas sent off site for sulfur recovery, calculate and report 

CO2 process emissions from sulfur recovery plants according 

to the requirements in paragraphs (f)(1) through (f)(5) of 

this section, or, for non-Claus sulfur recovery plants, 

according to the requirements in paragraph (j) of this 

section regardless of the concentration of CO2 in the vented 

gas stream. Combustion emissions from the sulfur recovery 

plant (e.g., from fuel combustion in the Claus burner or 

the tail gas treatment incinerator) must be reported under 

subpart C of this part (General Stationary Fuel Combustion 

Sources). For the purposes of this subpart, the sour gas 

stream for which monitoring is required according to 
316

paragraphs (f)(2) through (f)(5) of this section is not 

considered a fuel.

(1) If you operate and maintain a CEMS that measures 

CO2 emissions according to subpart C of this part, you must 

calculate CO2 emissions under this subpart by following the 

Tier 4 Calculation Methodology specified in §98.33(a)(4) 

and all associated requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel Combustion Sources). 

You must monitor fuel use in the Claus burner, tail gas 

incinerator, or other combustion sources that discharge via 

the final exhaust stack from the sulfur recovery plant and 

calculate the combustion emissions from the fuel use 

according to subpart C of this part. Calculate the process 

emissions from the sulfur recovery plant as the difference 

in the CO2 CEMS emissions and the calculated combustion 

emissions associated with the sulfur recovery plant final 

exhaust stack. Other sulfur recovery plants must either 

install a CEMS that complies with the Tier 4 Calculation 

Methodology in subpart C, or follow the requirements of 

paragraphs (f)(2) through (f)(5) of this section, or (for 

non-Claus sulfur recovery plants only) follow the 

requirements in paragraph (j) of this section to determine 

CO2 emissions for the sulfur recovery plant. 
317

(2) Flow measurement. If you have a continuous flow 

monitor on the sour gas feed to the sulfur recovery plant, 

you must use the measured flow rates when the monitor is 

operational to calculate the sour gas flow rate. If you do 

not have a continuous flow monitor on the sour gas feed to 

the sulfur recovery plant, you must use engineering 

calculations, company records, or similar estimates of 

volumetric sour gas flow. 

(3) Carbon content. If you have a continuous gas 

composition monitor capable of measuring carbon content on 

the sour gas feed to the sulfur recovery plant or if you 

monitor gas composition for carbon content on a routine 

basis, you must use the measured carbon content value. 

Alternatively, you may develop a site-specific carbon 

content factor using limited measurement data or 

engineering estimates or use the default factor of 0.20.

(4) Calculate the CO2 emissions from each sulfur 

recovery plant using Equation Y-12 of this section. 

* * 0.001 44 *

2 SG MFC MVC

CO  F

(Eq. Y-12)

Where:

CO2 = Annual CO2 emissions (metric tons/year).

FSG = Volumetric flow rate of sour gas feed (including 

sour water stripper gas) to the sulfur recovery 

plant (scf/year).
318

44 = Molecular weight of CO2 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole

at 68 oF and 14.7 psia or 836.6 scf/kg-mole at 60 

oF and 14.7 psia).

MFC = Mole fraction of carbon in the sour gas to the 

sulfur recovery plant (kg-mole C/kg-mole gas); 

default = 0.20.

0.001 = Conversion factor, kg to metric tons

(5) If tail gas is recycled to the front of the 

sulfur recovery plant and the recycled flow rate and carbon 

content is included in the measured data under paragraphs 

(f)(2) and (f)(3) of this section, respectively, then the 

annual CO2 emissions calculated in paragraph (f)(4) of this 

section must be corrected to avoid double counting these 

emissions. You may use engineering estimates to perform 

this correction or assume that the corrected CO2 emissions 

are 95 percent of the uncorrected value calculated using 

Equation Y-12 of this section. 

(g) For coke calcining units, calculate GHG emissions 

according to the applicable provisions in paragraphs (g)(1) 

through (g)(3) of this section.

(1) If you operate and maintain a CEMS that measures 

CO2 emissions according to subpart C of this part, you must 

calculate and report CO2 emissions under this subpart by 

following the Tier 4 Calculation Methodology specified in 

§98.33(a)(4) and all associated requirements for Tier 4 in 

subpart C of this part (General Stationary Fuel Combustion 
319

Sources). You must monitor fuel use in the coke calcining 

unit that discharges via the final exhaust stack from the 

coke calcining unit and calculate the combustion emissions 

from the fuel use according to subpart C of this part. 

Calculate the process emissions from the coke calcining 

unit as the difference in the CO2 CEMS emissions and the 

calculated combustion emissions associated with the coke 

calcining unit final exhaust stack. Other coke calcining 

units must either install a CEMS that complies with the 

Tier 4 Calculation Methodology in subpart C of this part, 

or follow the requirements of paragraph (g)(2) of this 

section.

(2) Calculate the CO2 emissions from the coke 

calcining unit using Equation Y-13 of this section.

    CO M in CCGC M out M dust CC MPC* * *

12

44

2   

(Eq. Y-13)

Where:

CO2 = Annual CO2 emissions (metric tons/year).

Min = Annual mass of green coke fed to the coke 

calcining unit from facility records (metric 

tons/year).

CCGC = Average mass fraction carbon content of green 

coke from facility measurement data (metric ton 

carbon/metric ton green coke).

Mout = Annual mass of marketable petroleum coke 

produced by the coke calcining unit from 

facility records (metric tons petroleum 

coke/year).
320

Mdust = Annual mass of petroleum coke dust removed from 

the process through the dust collection system 

of the coke calcining unit from facility records 

(metric ton petroleum coke dust/year). For coke 

calcining units that recycle the collected dust, 

the mass of coke dust removed from the process 

is the mass of coke dust collected less the mass 

of coke dust recycled to the process.

CCMPC = Average mass fraction carbon content of 

marketable petroleum coke produced by the coke 

calcining unit from facility measurement data 

(metric ton carbon/metric ton petroleum coke).

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

(3) For all coke calcining units, use the CO2

emissions from the coke calcining unit calculated in 

paragraphs (g)(1) or (g)(2), as applicable, and calculate 

CH4 using the methods described in paragraph (c)(4) of this 

section and N2O emissions using the methods described in 

paragraph (c)(5) of this section.

(h) For asphalt blowing operations, calculate CO2 and 

CH4 emissions according to the requirements in paragraph (j) 

of this section regardless of the CO2 and CH4 concentrations 

or according to the applicable provisions in paragraphs 

(h)(1) and (h)(2) of this section.

(1) For uncontrolled asphalt blowing operations or 

asphalt blowing operations controlled by vapor scrubbing, 

calculate CO2 and CH4 emissions using Equations Y-14 and Y15 of this section, respectively. 
321

  CO2  QAB  EFAB.CO2 (Eq. Y-14)

Where:

CO2 = Annual CO2 emissions from uncontrolled asphalt 

blowing (metric tons CO2/year).

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CO2 = Emission factor for CO2 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CO2/MMbbl asphalt blown); default = 1,100.

  CH 4  QAB  EFAB,CH 4 (Eq. Y-15)

Where:

CH4 = Annual methane emissions from uncontrolled 

asphalt blowing (metric tons CH4/year).

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CH4/MMbbl asphalt blown); default = 580.

(2) For asphalt blowing operations controlled by 

thermal oxidizer or flare, calculate CO2 using either 

Equation Y-16a or Equation Y-16b of this section and 

calculate CH4 emissions using Equation Y-17 of this section, 

provided these emissions are not already included in the 

flare emissions calculated in paragraph (b) of this section 

or in the stationary combustion unit emissions required 

under subpart C of this part (General Stationary Fuel 

Combustion Sources). 













   

12

44 0.98 CO2 QAB CEFAB (Eq. Y-16a)
322

Where:

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year).

0.98 = Assumed combustion efficiency of thermal oxidizer 

or flare.

QAB = Quantity of asphalt blown (MMbbl/year).

CEFAB = Carbon emission factor from asphalt blowing from 

facility-specific test data (metric tons C/MMbbl 

asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole). 





























 











2   , 2    , 2

12

44 0.98 CO QAB EFAB CO CEFAB EFAB CO (Eq. Y-16b)

Where:

CO2 = Annual CO2 emissions from controlled asphalt 

blowing (metric tons CO2/year).

QAB = Quantity of asphalt blown (MMbbl/year).

0.98 = Assumed combustion efficiency of thermal oxidizer 

or flare.

EFAB,CO2 = Emission factor for CO2 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CO2/MMbbl asphalt blown); default = 1,100.

CEFAB = Carbon emission factor from asphalt blowing from 

facility-specific test data (metric tons C/MMbbl 

asphalt blown); default = 2,750.

44 = Molecular weight of CO2 (kg/kg-mole).

12 = Atomic weight of C (kg/kg-mole).

  4 , 40.02 CH   QAB  EFAB CH (Eq. Y-17)

Where:

CH4 = Annual methane emissions from controlled asphalt 

blowing (metric tons CH4/year).
323

0.02 = Fraction of methane uncombusted in thermal 

oxidizer or flare based on assumed 98% combustion 

efficiency.

QAB = Quantity of asphalt blown (million barrels per 

year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4 from uncontrolled asphalt 

blowing from facility-specific test data (metric 

tons CH4/MMbbl asphalt blown); default = 580.

(i) For delayed coking units, calculate the CH4

emissions from the depressurization of the coking unit 

vessel (i.e., the "coke drum") to atmosphere using either 

of the methods provided in paragraphs (i)(1) or (i)(2), 

provided no water or steam is added to the vessel once it 

is vented to the atmosphere. You must use the method in 

paragraph (i)(1) of this section if you add water or steam 

to the vessel after it is vented to the atmosphere.

(1) Use the process vent method in paragraph (j) of 

this section to calculate the CH4 emissions from the 

depressurization of the coke drum or vessel regardless of 

the CH4 concentration and also calculate the CH4 emissions 

from the subsequent opening of the vessel for coke cutting 

operations using Equation Y-18 of this section. If you 

have coke drums or vessels of different dimensions, use the

process vent method in paragraph (j) of this section and 

Equation Y-18 for each set of coke drums or vessels of the 

same size and sum the resultant emissions across each set 
324

of coke drums or vessels to calculate the CH4 emissions for 

all delayed coking units.

 

















  



 



   0.001 16

14.7 4

14.7

4

2

4 void CH

CV MF

MVC

D

f

P

CH N H



(Eq. Y-18)

Where:

CH4 = Annual methane emissions from the delayed coking 

unit vessel opening (metric ton/year).

N = Cumulative number of vessel openings for all 

delayed coking unit vessels of the same 

dimensions during the year.

H = Height of coking unit vessel (feet).

PCV = Gauge pressure of the coking vessel when opened 

to the atmosphere prior to coke cutting or, if 

the alternative method provided in paragraph 

(i)(2) of this section is used, gauge pressure of 

the coking vessel when depressurization gases are 

first routed to the atmosphere (pounds per square 

inch gauge, psig)

14.7 = Assumed atmospheric pressure (pounds per square 

inch, psi)

fvoid = Volumetric void fraction of coking vessel prior 

to steaming (cf gas/cf of vessel); default = 0.6.

D = Diameter of coking unit vessel (feet).

16 = Molecular weight of CH4 (kg/kg-mole). 

MVC = Molar volume conversion factor (849.5 scf/ kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia).

MFCH4 = Mole fraction of methane in coking vessel gas 

(kg-mole CH4/kg-mole gas, wet basis); default 

value is 0.01.

0.001 = Conversion factor (metric ton/kg).

(2) Calculate the CH4 emissions from the 

depressurization vent and subsequent opening of the vessel 

for coke cutting operations using Equation Y-18 of this 
325

section and the pressure of the coking vessel when the 

depressurization gases are first routed to the atmosphere. 

If you have coke drums or vessels of different dimensions, 

use Equation Y-18 for each set of coke drums or vessels of 

the same size and sum the resultant emissions across each 

set of coke drums or vessels to calculate the CH4 emissions 

for all delayed coking units.

(j) For each process vent not covered in paragraphs 

(a) through (i) of this section that can be reasonably 

expected to contain greater than 2 percent by volume CO2 or 

greater than 0.5 percent by volume of CH4 or greater than 

0.01 percent by volume (100 parts per million) of N2O, 

calculate GHG emissions using the Equation Y-19 of this 

section. You must use Equation Y-19 of this section to 

calculate CH4 emissions for catalytic reforming unit 

depressurization and purge vents when methane is used as 

the purge gas or if you elected this method as an 

alternative to the methods in paragraphs (f), (h), or (k)

of this section. 

      















    

N

p

p

x

x p x p

VT

MVC

MW E VR MF

1

0.001 (Eq. Y-19)

Where:

Ex = Annual emissions of each GHG from process vent 

(metric ton/yr).

N = Number of venting events per year.
326

P = Index of venting events.

(VR)p = Average volumetric flow rate of process gas 

during the event (scf per hour) from measurement 

data, process knowledge, or engineering 

estimates.

(MFx)p = Mole fraction of GHG x in process vent during 

the event (kg-mol of GHG x/kg-mol vent gas) from 

measurement data, process knowledge, or 

engineering estimates.

MWx = Molecular weight of GHG x (kg/kg-mole); use 44 

for CO2 or N2O and 16 for CH4.

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia).

(VT)p = Venting time for the event, (hours).

0.001 = Conversion factor (metric ton/kg) 

(k) For uncontrolled blowdown systems, you must 

calculate CH4 emissions either using the methods for 

process vents in paragraph (j) of this section regardless 

of the CH4 concentration or using Equation Y-20 of this 

section. Blowdown systems where the uncondensed gas stream 

is routed to a flare or similar control device is 

considered to be controlled and is not required to estimate 

emissions under this paragraph (k).













    0.001 16

4 Re MVC

CH Q f EFBD (Eq. Y-20)

Where:

CH4 = Methane emission rate from blowdown systems (mt 

CH4/year).

QRef = Quantity of crude oil plus the quantity of 

intermediate products received from off site 

that are processed at the facility (MMbbl/year).
327

EFBD = Methane emission factor for uncontrolled blown 

systems (scf CH4/MMbbl); default is 137,000.

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(l) For equipment leaks, calculate CH4 emissions using 

the method specified in either paragraph (l)(1) or (l)(2) 

of this section.

(1) Use process-specific methane composition data 

(from measurement data or process knowledge) and any of the 

emission estimation procedures provided in the Protocol for 

Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS 

PB96-175401).

(2) Use Equation Y-21 of this section. 

  CH   NCD   NPU   NPU  3 N H  6 NFGS 0.4 0.2 0.1 4.

4 1 2 2 (Eq. Y-21)

Where:

CH4 = Annual methane emissions from equipment leaks 

(metric tons/year)

NCD = Number of atmospheric crude oil distillation 

columns at the facility.

NPU1 = Cumulative number of catalytic cracking units, 

coking units (delayed or fluid), hydrocracking, 

and full-range distillation columns (including 

depropanizer and debutanizer distillation 

columns) at the facility.

NPU2 = Cumulative number of hydrotreating/hydrorefining 

units, catalytic reforming units, and visbreaking 

units at the facility.

NH2 = Total number of hydrogen plants at the facility.
328

NFGS = Total number of fuel gas systems at the facility. 

(m) For storage tanks, except as provided in 

paragraph (m)(4) of this section, calculate CH4 emissions 

using the applicable methods in paragraphs (m)(1) through

(m)(3) of this section.

(1) For storage tanks other than those processing 

unstabilized crude oil, you must either calculate CH4

emissions from storage tanks that have a vapor-phase 

methane concentration of 0.5 volume percent or more using 

tank-specific methane composition data (from measurement 

data or product knowledge) and the AP-42 emission 

estimation methods provided in Section 7.1 of the AP-42: 

“Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources”, including TANKS Model 

(Version 4.09D) or similar programs, or estimate CH4

emissions from storage tanks using Equation Y-22 of this 

section. 

  CH 4 QRe f  0.1 (Eq. Y-22)

Where:

CH4 = Annual methane emissions from storage tanks 

(metric tons/year).

0.1 = Default emission factor for storage tanks (metric 

ton CH4/MMbbl).

QRef = Quantity of crude oil plus the quantity of 

intermediate products received from off site that 

are processed at the facility (MMbbl/year).
329

(2) For storage tanks that process unstabilized crude 

oil, calculate CH4 emissions from the storage of 

unstabilized crude oil using either tank-specific methane 

composition data (from measurement data or product 

knowledge) and direct measurement of the gas generation 

rate or by using Equation Y-23 of this section. 

0.001 16 (995,000 )

4     4  

MVC

CH Qun P MFCH (Eq. Y-23)

Where:

CH4 = Annual methane emissions from storage tanks 

(metric tons/year).

Qun = Quantity of unstabilized crude oil received at 

the facility (MMbbl/year).

ΔP = Pressure differential from the previous storage 

pressure to atmospheric pressure (pounds per 

square inch, psi).

MFCH4 = Average mole fraction of CH4 in vent gas from the 

unstabilized crude oil storage tanks from 

facility measurements (kg-mole CH4/kg-mole gas); 

use 0.27 as a default if measurement data are 

not available.

995,000 = Correlation Equation factor (scf gas per MMbbl 

per psi)

16 = Molecular weight of CH4 (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kgmole at 68 oF and 14.7 psia or 836.6 scf/kg-mole 

at 60 oF and 14.7 psia).

0.001 = Conversion factor (metric ton/kg).

(3) You do not need to calculate CH4 emissions from 

storage tanks that meet any of the following descriptions: 
330

(i) Units permanently attached to conveyances such as 

trucks, trailers, rail cars, barges, or ships; 

(ii) Pressure vessels designed to operate in excess 

of 204.9 kilopascals and without emissions to the 

atmosphere;

(iii) Bottoms receivers or sumps;

(iv) Vessels storing wastewater; or

(v) Reactor vessels associated with a manufacturing 

process unit.

(n) For crude oil, intermediate, or product loading 

operations for which the vapor-phase concentration of 

methane is 0.5 volume percent or more, calculate CH4

emissions from loading operations using vapor-phase methane 

composition data (from measurement data or process 

knowledge) and the emission estimation procedures provided 

in Section 5.2 of the AP-42: “Compilation of Air Pollutant 

Emission Factors, Volume 1: Stationary Point and Area 

Sources.” For loading operations in which the vapor-phase 

concentration of methane is less than 0.5 volume percent, 

you may assume zero methane emissions.

§98.254 Monitoring and QA/QC requirements. 

(a) Fuel flow meters, gas composition monitors, and 

heating value monitors that are associated with sources

that use a CEMS to measure CO2 emissions according to 
331

subpart C of this part or that are associated with 

stationary combustion sources must meet the applicable 

monitoring and QA/QC requirements in §98.34. 

(b) All gas flow meters, gas composition monitors, 

and heating value monitors that are used to provide data 

for the GHG emissions calculations in this subpart for 

sources other than those subject to the requirements in 

paragraph (a) of this section shall be calibrated according 

to the procedures in the applicable methods specified in 

paragraphs (c) through (g) of this section or the 

procedures specified by the manufacturer. In the case of 

gas flow meters, all gas flow meters must meet the 

calibration accuracy requirements in §98.3(i). You must 

recalibrate each gas flow meter according to one of the 

following frequencies. You may recalibrate either 

biennially (every two years), at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. You must 

recalibrate each gas composition monitor and heating value 

monitor according to one of the following frequencies. You 

may recalibrate either annually, at the minimum frequency 

specified by the manufacturer, or at the interval specified 

by the industry consensus standard practice used. 
332

(c) For flare or sour gas flow meters, operate, 

calibrate, and maintain the flow meter according to one of 

the following. You may use a method published by a 

consensus-based standards organization or the procedures 

specified by the flow meter manufacturer. Consensus-based 

standards include, but are not limited to, the following: 

ASTM International, the American Society of Mechanical 

Engineers (ASME), and the American Gas Association (AGA).

(d) Except as provided in paragraph (g) of this 

section, determine gas composition and, if required, 

average molecular weight of the gas using any of the 

following methods. Alternatively, the results of 

chromatographic analysis of the fuel may be used, provided 

that the gas chromatograph is operated, maintained, and 

calibrated according to the manufacturer’s instructions; 

and the methods used for operation, maintenance, and 

calibration of the gas chromatograph are documented in the 

written Monitoring Plan for the unit under §98.3(g)(5).

(1) Method 18 at 40 CFR part 60, appendix A-6.

(2) ASTM D1945-03 Standard Test Method for Analysis 

of Natural Gas by Gas Chromatography (incorporated by 

reference, see §98.7).
333

(3) ASTM D1946-90 (Reapproved 2006) Standard Practice 

for Analysis of Reformed Gas by Gas Chromatography 

(incorporated by reference, see §98.7). 

(4) GPA 2261–00 Analysis for Natural Gas and Similar 

Gaseous Mixtures by Gas Chromatography (incorporated by 

reference, see §98.7).

(5) UOP539-97 Refinery Gas Analysis by Gas 

Chromatography (incorporated by reference, see §98.7). 

(6) ASTM D2503-92 (Reapproved 2007) Standard Test 

Method for Relative Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric Measurement of Vapor 

Pressure (incorporated by reference, see §98.7).

(e) Determine flare gas higher heating value using 

any of the following methods. Alternatively, the results 

of chromatographic analysis of the fuel may be used, 

provided that the gas chromatograph is operated, 

maintained, and calibrated according to the manufacturer’s 

instructions; and the methods used for operation, 

maintenance, and calibration of the gas chromatograph are 

documented in the written Monitoring Plan for the unit 

under §98.3(g)(5).

(1) ASTM D4809-06 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 

(Precision Method) (incorporated by reference, see §98.7). 
334

(2) ASTM D240-02 (Reapproved 2007) Standard Test 

Method for Heat of Combustion of Liquid Hydrocarbon Fuels 

by Bomb Calorimeter (incorporated by reference, see §98.7).

(3) ASTM D1826-94 (Reapproved 2003) Standard Test 

Method for Calorific (Heating) Value of Gases in Natural 

Gas Range by Continuous Recording Calorimeter (incorporated 

by reference, see §98.7).

(4) ASTM D3588-98 (Reapproved 2003) Standard Practice 

for Calculating Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels (incorporated by 

reference, see §98.7).

(5) ASTM D4891-89 (Reapproved 2006) Standard Test 

Method for Heating Value of Gases in Natural Gas Range by 

Stoichiometric Combustion (incorporated by reference, see 

§98.7).

(f) For gas flow meters used to comply with the 

requirements in §98.253(c)(2)(ii) or §98.253(j), install, 

operate, calibrate, and maintain each gas flow meter 

according to the requirements in 40 CFR 63.1572(c) and the 

following requirements. 

(1) Locate the flow monitor at a site that provides 

representative flow rates. Avoid locations where there is

swirling flow or abnormal velocity distributions due to 

upstream and downstream disturbances.
335

(2) [Reserved]

(3) Use a continuous monitoring system capable of 

correcting for the temperature, pressure, and moisture 

content to output flow in dry standard cubic feet (standard 

conditions as defined in §98.6).

(g) For exhaust gas CO2/CO/O2 composition monitors 

used to comply with the requirements in §98.253(c)(2), 

install, operate, calibrate, and maintain exhaust gas 

composition monitors according to the the requirements in 

40 CFR 60.105a(b)(2) or 40 CFR 63.1572(c) or according to 

the manufacturer’s specifications and requirements.

(h) Determine the mass of petroleum coke as required 

by Equation Y-13 of this subpart using mass measurement 

equipment meeting the requirements for commercial weighing 

equipment as described in Specifications, Tolerances, and 

Other Technical Requirements For Weighing and Measuring 

Devices, NIST Handbook 44 (2009) (incorporated by 

reference, see §98.7). Calibrate the measurement device 

according to the procedures specified by NIST handbook 44 

or the procedures specified by the manufacturer. 

Recalibrate either biennially or at the minimum frequency 

specified by the manufacturer.

(i) Determine the carbon content of petroleum coke as 

required by Equation Y-13 of this subpart using any one of 
336

the following methods. Calibrate the measurement device 

according to procedures specified by the method or 

procedures specified by the measurement device 

manufacturer.

(1) ASTM D3176-89 (Reapproved 2002) Standard Practice 

for Ultimate Analysis of Coal and Coke (incorporated by 

reference, see §98.7). 

(2) ASTM D5291-02 (Reapproved 2007) Standard Test 

Methods for Instrumental Determination of Carbon, Hydrogen, 

and Nitrogen in Petroleum Products and Lubricants 

(incorporated by reference, see §98.7).

(3) ASTM D5373-08 Standard Test Methods for 

Instrumental Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal (incorporated by 

reference, see §98.7).

(j) Determine the quantity of petroleum process 

streams using company records. These quantities include 

the quantity of asphalt blown, quantity of crude oil plus 

the quantity of intermediate products received from off 

site, and the quantity of unstabilized crude oil received 

at the facility.

(k) The owner or operator shall document the 

procedures used to ensure the accuracy of the estimates of 

fuel usage, gas composition, and heating value including 
337

but not limited to calibration of weighing equipment, fuel 

flow meters, and other measurement devices. The estimated 

accuracy of measurements made with these devices shall also 

be recorded, and the technical basis for these estimates 

shall be provided. 

§98.255 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required (e.g., 

concentrations, flow rates, fuel heating values, carbon 

content values). Therefore, whenever a quality-assured 

value of a required parameter is unavailable (e.g., if a 

CEMS malfunctions during unit operation or if a required 

fuel sample is not taken), a substitute data value for the 

missing parameter shall be used in the calculations. 

(a) For stationary combustion sources, use the 

missing data procedures in subpart C of this part.

(b) For each missing value of the heat content, 

carbon content, or molecular weight of the fuel, substitute 

the arithmetic average of the quality-assured values of 

that parameter immediately preceding and immediately 

following the missing data incident. If the “after” value 

is not obtained by the end of the reporting year, you may 

use the “before” value for the missing data substitution. 

If, for a particular parameter, no quality-assured data are 
338

available prior to the missing data incident, the 

substitute data value shall be the first quality-assured 

value obtained after the missing data period.

(c) For missing CO2, CO, O2, CH4, or N2O 

concentrations, gas flow rate, and percent moisture, the

substitute data values shall be the best available 

estimate(s) of the parameter(s), based on all available 

process data (e.g., processing rates, operating hours, 

etc.). The owner or operator shall document and keep 

records of the procedures used for all such estimates.

(d) For hydrogen plants, use the missing data 

procedures in subpart P of this part.

§98.256 Data reporting requirements. 

In addition to the reporting requirements of §98.3(c), 

you must report the information specified in paragraphs (a) 

through (q) of this section.

(a) For combustion sources, follow the data reporting 

requirements under subpart C of this part (General 

Stationary Fuel Combustion Sources).

(b) For hydrogen plants, follow the data reporting 

requirements under subpart P of this part (Hydrogen 

Production). 

(c) [Reserved]

(d) [Reserved]
339

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam 

assisted, air-assisted).

(3) A description of the flare service (general 

facility flare, unit flare, emergency only or back-up 

flare).

(4) The calculated CO2, CH4, and N2O annual emissions 

for each flare, expressed in metric tons of each pollutant 

emitted.

(5) A description of the method used to calculate the 

CO2 emissions for each flare (e.g., reference section and 

equation number). 

(6) If you use Equation Y-1a of this subpart, an 

indication of whether daily or weekly measurement periods 

are used, the annual volume of flare gas combusted (in 

scf/year) and the annual average molecular weight (in 

kg/kg-mole), the molar volume conversion factor (in scf/kgmole), and annual average carbon content of the flare gas 

(in kg carbon per kg flare gas).

(7) If you use Equation Y-1b of this subpart, an 

indication of whether daily or weekly measurement periods 

are used, the annual volume of flare gas combusted (in 

scf/year), the molar volume conversion factor (in scf/kg-
340

mole), the annual average CO2 concentration (volume or mole 

percent), the number of carbon containing compounds other 

than CO2 in the flare gas stream, and for each of the carbon 

containing compounds other than CO2 in the flare gas stream:

(i) The annual average concentration of the compound 

(volume or mole percent).

(ii) The carbon mole number of the compound (moles 

carbon per mole compound).

(8) If you use Equation Y-2 of this subpart, an 

indication of whether daily or weekly measurement periods 

are used, the annual volume of flare gas combusted (in 

million (MM) scf/year) and the annual average higher 

heating value of the flare gas (in MMBtu per MMscf).

(9) If you use Equation Y-3 of this subpart, the 

annual volume of flare gas combusted (in MMscf/year) during 

normal operations, the annual average higher heating value 

of the flare gas (in MMBtu/MMscf), the number of SSM events 

exceeding 500,000 scf/day, the volume of gas flared (in 

scf/event), the average molecular weight (in kg/kg-mole), 

the molar volume conversion factor (in scf/kg-mole), and 

carbon content of the flare gas (in kg carbon per kg flare) 

for each SSM event over 500,000 scf/day.
341

(10) The fraction of carbon in the flare gas 

contributed by methane used in Equation Y-4 of this subpart 

and the basis for its value.

(f) For catalytic cracking units, traditional fluid 

coking units, and catalytic reforming units, owners and 

operators shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid 

catalytic cracking unit, thermal catalytic cracking unit, 

traditional fluid coking unit, or catalytic reforming 

unit).

(3) Maximum rated throughput of the unit, in 

bbl/stream day.

(4) The calculated CO2, CH4, and N2O annual emissions 

for each unit, expressed in metric tons of each pollutant 

emitted.

(5) A description of the method used to calculate the 

CO2 emissions for each unit (e.g., reference section and 

equation number).

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS (unadjusted to remove CO2 combustion emissions 

associated with additional units, if present) and the 
342

process CO2 emissions as calculated according to 

§98.253(c)(1)(ii). Report the CO2 annual emissions 

associated with sources other than those from the coke 

burn-off in the applicable subpart (e.g., subpart C of this 

part in the case of a CO boiler).

(7) If you use Equation Y-6 of this subpart, the 

annual average exhaust gas flow rate, %CO2, %CO, and the 

molar volume conversion factor (in scf/kg-mole).

(8) If you use Equation Y-7a of this subpart, the 

annual average flow rate of inlet air and oxygen-enriched 

air, %O2, %Ooxy, %CO2, and %CO. 

(9) If you use Equation Y-7b of this subpart, the 

annual average flow rate of inlet air and oxygen-enriched 

air, %N2,oxy, and %N2,exhaust.

(10) If you use Equation Y-8 of this subpart, the 

coke burn-off factor, annual throughput of unit, and the 

average carbon content of coke and the basis for the value.

(11) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for CH4 emissions. If you use a unit-specific emission 

factor for CH4, report the unit-specific emission factor for 

CH4, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 
343

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor.

(12) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for N2O emissions. If you use a unit-specific emission 

factor for N2O, report the unit-specific emission factor for 

N2O, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor. 

(13) If you use Equation Y-11 of this subpart, the 

number of regeneration cycles or measurement periods during 

the reporting year, the average coke burn-off quantity per 

cycle or measurement period, and the average carbon content 

of the coke. 

(g) For fluid coking unit of the flexicoking type, 

the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in 

bbl/stream day.

(4) Indicate whether the GHG emissions from the low 

heat value gas are accounted for in subpart C of this part 

or §98.253(c). 
344

(5) If the GHG emissions for the low heat value gas 

are calculated at the flexicoking unit, also report the 

calculated annual CO2, CH4, and N2O emissions for each unit, 

expressed in metric tons of each pollutant emitted, and the 

applicable equation input parameters specified in 

paragraphs (f)(7) through (f)(13) of this section.

(h) For sulfur recovery plants and for emissions from 

sour gas sent off-site for sulfur recovery, the owner and 

operator shall report:

(1) The plant ID number (if applicable).

(2) Maximum rated throughput of each independent 

sulfur recovery plant, in metric tons sulfur 

produced/stream day, a description of the type of sulfur 

recovery plant, and an indication of the method used to 

calculate CO2 annual emissions for the sulfur recovery plant 

(e.g., CO2 CEMS, Equation Y-12, or process vent method in 

§98.253(j)).

(3) The calculated CO2 annual emissions for each 

sulfur recovery plant, expressed in metric tons. The 

calculated annual CO2 emissions from sour gas sent off-site 

for sulfur recovery, expressed in metric tons.

(4) If you use Equation Y-12 of this subpart, the 

annual volumetric flow to the sulfur recovery plant (in 

scf/year), the molar volume conversion factor (in scf/kg-
345

mole), and the annual average mole fraction of carbon in 

the sour gas (in kg-mole C/kg-mole gas). 

(5) If you recycle tail gas to the front of the 

sulfur recovery plant, indicate whether the recycled flow 

rate and carbon content are included in the measured data 

under §98.253(f)(2) and (3). Indicate whether a correction 

for CO2 emissions in the tail gas was used in Equation Y-12. 

If so, then report the value of the correction, the annual 

volume of recycled tail gas (in scf/year) and the annual 

average mole fraction of carbon in the tail gas (in kg-mole 

C/kg-mole gas). Indicate whether you used the default (95%) 

or a unit specific correction, and if used, report the 

approach used. 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS and the annual process CO2 emissions calculated 

according to §98.253(f)(1). Report the CO2 annual emissions 

associated with fuel combustion subpart C of this part 

(General Stationary Fuel Combustion Sources).

(7) If you use the process vent method in §98.253(j) 

for a non-Claus sulfur recovery plant, the relevant 

information required under paragraph (l)(5) of this 

section.
346

(i) For coke calcining units, the owner and operator 

shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric 

tons coke calcined/stream day.

(3) The calculated CO2, CH4, and N2O annual emissions 

for each unit, expressed in metric tons of each pollutant 

emitted.

(4) A description of the method used to calculate the 

CO2 emissions for each unit (e.g., reference section and 

equation number).

(5) If you use Equation Y-13 of this subpart, annual 

mass and carbon content of green coke fed to the unit, the 

annual mass and carbon content of marketable coke produced, 

the annual mass of coke dust removed from the process 

through dust collection systems, and an indication of 

whether coke dust is recycled to the unit (e.g., all dust 

is recycled, a portion of the dust is recycled, or none of 

the dust is recycled).

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured by the 

CEMS and the annual process CO2 emissions calculated 

according to §98.253(g)(1). Report the CO2 annual emissions 
347

associated with fuel combustion under subpart C of this 

part (General Stationary Fuel Combustion Sources).

(7) Indicate whether you use a measured value, a 

unit-specific emission factor or a default for CH4

emissions. If you use a unit-specific emission factor for 

CH4, the unit-specific emission factor for CH4, the units of 

measure for the unit-specific factor, the activity data for 

calculating emissions (e.g., if the emission factor is 

based on coke burn-off rate, the annual quantity of coke 

burned), and the basis for the factor. 

(8) Indicate whether you use a measured value, a 

unit-specific emission factor, or a default emission factor 

for N2O emissions. If you use a unit-specific emission 

factor for N2O, report the unit-specific emission factor for 

N2O, the units of measure for the unit-specific factor, the 

activity data for calculating emissions (e.g., if the 

emission factor is based on coke burn-off rate, the annual 

quantity of coke burned), and the basis for the factor. .

(j) For asphalt blowing operations, the owner or 

operator shall report:

(1) The unit ID number (if applicable).

(2) The quantity of asphalt blown (in Million bbl) at 

the unit in the reporting year.
348

(3) The type of control device used to reduce methane 

(and other organic) emissions from the unit.

(4) The calculated annual CO2 and CH4 emissions for 

each unit, expressed in metric tons of each pollutant 

emitted.

(5) If you use Equation Y-14 of this subpart, the CO2

emission factor used and the basis for the value. 

(6) If you use Equation Y-15 of this subpart, the CH4

emission factor used and the basis for the value.

(7) If you use Equation Y-16a of this subpart, the 

carbon emission factor used and the basis for the value. 

(8) If you use Equation Y-16b of this subpart, the CO2

emission factor used and the basis for its value and the 

carbon emission factor used and the basis for its value.

(9) If you use Equation Y-17 of this subpart, the CH4

emission factor used and the basis for the value.

(k) For delayed coking units, the owner or operator 

shall report:

(1) The cumulative annual CH4 emissions (in metric 

tons of CH4) for all delayed coking units at the facility.

(2) A description of the method used to calculate the 

CH4 emissions for each unit (e.g., reference section and 

equation number).
349

(3) The total number of delayed coking units at the 

facility, the total number of delayed coking drums at the 

facility, and for each coke drum or vessel: the dimensions, 

the typical gauge pressure of the coking drum when first 

vented to the atmosphere, typical void fraction, the 

typical drum outage (i.e. the unfilled distance from the 

top of the drum, in feet), the molar volume conversion 

factor (in scf/kg-mole), and annual number of coke-cutting 

cycles.

(4) For each set of coking drums that are the same 

dimensions: the number of coking drums in the set, the 

height and diameter of the coke drums (in feet), the 

cumulative number of vessel openings for all delayed coking 

drums in the set, the typical venting pressure (in psig), 

void fraction (in cf gas/cf of vessel), and the mole 

fraction of methane in coking gas (in kg-mole CF4/kg-mole 

gas, wet basis).

(5) The basis for the volumetric void fraction of the 

coke vessel prior to steaming and the basis for the mole 

fraction of methane in the coking gas. 

(l) For each process vent subject to §98.253(j), the 

owner or operator shall report:

(1) The vent ID number (if applicable).
350

(2) The unit or operation associated with the 

emissions.

(3) The type of control device used to reduce methane 

(and other organic) emissions from the unit, if applicable.

(4) The calculated annual CO2, CH4, and N2O emissions 

for each vent, expressed in metric tons of each pollutant 

emitted.

(5) The annual volumetric flow discharged to the 

atmosphere (in scf), and an indication of the measurement 

or estimation method, annual average mole fraction of each 

GHG above the concentration threshold or otherwise required 

to be reported and an indication of the measurement or 

estimation method, the molar volume conversion factor (in 

scf/kg-mole), and for intermittent vents, the number of 

venting events and the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or 

operator shall report:

(1) An indication of whether the uncontrolled 

blowdown emission are reported under §98.253(k) or 

§98.253(j) or a statement that the facility does not have 

any uncontrolled blowdown systems.

(2) The cumulative annual CH4 emissions (in metric 

tons of CH4) for uncontrolled blowdown systems.
351

(3) For uncontrolled blowdown systems reporting under 

§98.253(k), the total quantity (in Million bbl) of crude 

oil plus the quantity of intermediate products received 

from off-site that are processed at the facility in the 

reporting year, the methane emission factor used for 

uncontrolled blowdown systems, the basis for the value, and 

the molar volume conversion factor (in scf/kg-mole).

(4) For uncontrolled blowdown systems reporting under 

§98.253(j), the relevant information required under 

paragraph (l)(5) of this section.

(n) For equipment leaks, the owner or operator shall 

report:

(1) The cumulative CH4 emissions (in metric tons of 

each pollutant emitted) for all equipment leak sources.

(2) The method used to calculate the reported 

equipment leak emissions.

(3) The number of each type of emission source listed 

in Equation Y-21 of this subpart at the facility.

(o) For storage tanks, the owner or operator shall 

report:

(1) The cumulative annual CH4 emissions (in metric 

tons of CH4) for all storage tanks, except for those used to 

process unstabilized crude oil.
352

(2) For storage tanks other than those processing 

unstabilized crude oil:

(i) The method used to calculate the reported storage 

tank emissions for storage tanks other than those 

processing unstabilized crude (Section 7.1 of the AP-42: 

“Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources”, including TANKS Model 

(Version 4.09D) or similar programs, or Equation Y-22 of 

this section, other).

(ii) The total quantity (in MMbbl) of crude oil plus 

the quantity of intermediate products received from offsite that are processed at the facility in the reporting 

year.

(3) The cumulative CH4 emissions (in metric tons of 

CH4) for storage tanks used to process unstabilized crude 

oil or a statement that the facility did not receive any 

unstabilized crude oil during the reporting year. 

(4) For storage tanks that process unstabilized crude 

oil:

(i) The method used to calculate the reported 

unstabilized crude oil storage tank emissions.

(ii) The quantity of unstabilized crude oil received 

during the calendar year (in MMbbl).

(iii) The average pressure differential (in psi).
353

(iv) The molar volume conversion factor (in scf/kgmole).

(v) The average mole fraction of CH4 in vent gas from 

unstabilized crude oil storage tanks and the basis for the 

mole fraction.

(vi) If you did not use Equation Y-23, the tankspecific methane composition data and the gas generation 

rate data used to estimate the cumulative CH4 emissions for 

storage tanks used to process unstabilized crude oil.

(p) For loading operations, the owner or operator 

shall report:

(1) The cumulative annual CH4 emissions (in metric 

tons of each pollutant emitted) for loading operations.

(2) The quantity and types of materials loaded by 

vessel type (barge, tanker, marine vessel, etc.) that have 

an equilibrium vapor-phase concentration of methane of 0.5 

volume percent or greater, and the type of vessels in which 

the material is loaded.

(3) The type of control system used to reduce 

emissions from the loading of material with an equilibrium 

vapor-phase concentration of methane of 0.5 volume percent 

or greater, if any (submerged loading, vapor balancing, 

etc.).
354

(q) Name of each method listed in §98.254 or a 

description of manufacturer's recommended method used to 

determine a measured parameter.

§98.257 Records that must be retained. 

In addition to the records required by §98.3(g), you 

must retain the records of all parameters monitored under 

§98.255. If you comply with the combustion methodology in 

§98.252(a), then you must retain under this subpart the 

records required for the Tier 3 and/or Tier 4 Calculation 

Methodologies in §98.37 and you must keep records of the 

annual average flow calculations.

§98.258 Definitions. 

All terms used in this subpart have the same meaning given 

in the Clean Air Act and subpart A of this part.

Subpart AA—Pulp and Paper Manufacturing

§98.270 Definition of Source Category.

(a) The pulp and paper manufacturing source category 

consists of facilities that produce market pulp (i.e., 

stand-alone pulp facilities), manufacture pulp and paper 

(i.e., integrated facilities), produce paper products from 

purchased pulp, produce secondary fiber from recycled 

paper, convert paper into paperboard products (e.g., 

containers), or operate coating and laminating processes.
355

(b) The emission units for which GHG emissions must 

be reported are listed in paragraphs (b)(1) through (b)(5) 

of this section:

(1) Chemical recovery furnaces at kraft and soda 

mills (including recovery furnaces that burn spent pulping 

liquor produced by both the kraft and semichemical 

process).

(2) Chemical recovery combustion units at sulfite 

facilities.

(3) Chemical recovery combustion units at stand-alone 

semichemical facilities.

(4) Pulp mill lime kilns at kraft and soda 

facilities.

(5) Systems for adding makeup chemicals (CaCO3, 

Na2CO3) in the chemical recovery areas of chemical pulp 

mills.

§98.271 Reporting threshold.

You must report GHG emissions under this subpart if 

your facility contains a pulp and paper manufacturing 

process and the facility meets the requirements of either 

§98.2(a)(1) or (a)(2).

§98.272 GHGs to report.

You must report the emissions listed in paragraphs (a) 

through (f) of this section:
356

(a) CO2, biogenic CO2, CH4, and N2O emissions from each 

kraft or soda chemical recovery furnace.

(b) CO2, biogenic CO2, CH4, and N2O emissions from each 

sulfite chemical recovery combustion unit.

(c) CO2, biogenic CO2, CH4, and N2O emissions from each 

stand-alone semichemical chemical recovery combustion unit.

(d) CO2, biogenic CO2, CH4, and N2O emissions from each 

kraft or soda pulp mill lime kiln.

(e) CO2 emissions from addition of makeup chemicals 

(CaCO3, Na2CO3) in the chemical recovery areas of chemical 

pulp mills.

(f) CO2, CH4, and N2O combustion emissions from each

stationary combustion unit. You must calculate and report 

these emissions under subpart C of this part (General 

Stationary Fuel Combustion Sources) by following the 

requirements of subpart C.

§98.273 Calculating GHG emissions. 

(a) For each chemical recovery furnace located at a 

kraft or soda facility, you must determine CO2, biogenic 

CO2, CH4, and N2O emissions using the procedures in 

paragraphs (a)(1) through (a)(3) of this section. CH4 and 

N2O emissions must be calculated as the sum of emissions 

from combustion of fossil fuels and combustion of biomass 

in spent liquor solids.
357

(1) Calculate fossil fuel-based CO2 emissions from 

direct measurement of fossil fuels consumed and default 

emissions factors according to the Tier 1 methodology for 

stationary combustion sources in §98.33(a)(1). A higher 

tier from §98.33(a) may be used to calculate fossil fuelbased CO2 emissions if the respective monitoring and QA/QC 

requirements described in §98.34 are met. 

(2) Calculate fossil fuel-based CH4 and N2O emissions 

from direct measurement of fossil fuels consumed, default

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c).

(3) Calculate biogenic CO2 emissions and emissions of 

CH4 and N2O from biomass using measured quantities of spent 

liquor solids fired, site-specific HHV, and default or 

site-specific emissions factors, according to Equation AA-1 

of this section: 

CO2, CH 4, or N2O from biomass  (0.907 .18) Solids *HHV *EF

(Eq.AA-1)

Where: 

CO2, CH4, or N2O,

from Biomass = Biogenic CO2 emissions or emissions of 

CH4 or N2O from spent liquor solids 

combustion (metric tons per year).

Solids = Mass of spent liquor solids combusted 

(short tons per year) determined 

according to §98.274(b).
358

HHV = Annual high heat value of the spent 

liquor solids (mmBtu per kilogram) 

determined according to 98.274(b).

EF = Default emission factor for CO2, CH4, or 

N2O, from Table AA-1 of this subpart (kg 

CO2, CH4, or N2O per mmBtu).

0.90718 = Conversion factor from short tons to 

metric tons.

(b) For each chemical recovery combustion unit 

located at a sulfite or stand-alone semichemical facility, 

you must determine CO2, CH4, and N2O emissions using the 

procedures in paragraphs (b)(1) through (b)(4) of this 

section:

(1) Calculate fossil CO2 emissions from fossil fuels 

from direct measurement of fossil fuels consumed and 

default emissions factors according to the Tier 1 

Calculation Methodology for stationary combustion sources 

in §98.33(a)(1). A higher tier from §98.33(a) may be used 

to calculate fossil fuel-based CO2 emissions if the 

respective monitoring and QA/QC requirements described in 

§98.34 are met. 

(2) Calculate CH4 and N2O emissions from fossil fuels 

from direct measurement of fossil fuels consumed, default

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c).
359

(3) Calculate biogenic CO2 emissions using measured 

quantities of spent liquor solids fired and the carbon 

content of the spent liquor solids, according to Equation 

AA-2 of this section: 

Solids CC )

12

44 (0.90718 2 Biogenic CO     (Eq. AA-2)

Where: 

Biogenic CO2 = Annual CO2 mass emissions for spent liquor 

solids combustion (metric tons per year).

Solids = Mass of the spent liquor solids combusted 

(short tons per year) determined according 

to §98.274(b).

CC = Annual carbon content of the spent liquor 

solids, determined according to §98.274(b) 

(percent by weight, expressed as a decimal 

fraction, e.g., 95% = 0.95).

44/12 = Ratio of molecular weights, CO2 to carbon.

0.90718 = Conversion from short tons to metric tons

(4) Calculate CH4 and N2O emissions from biomass using 

Equation AA-1 of this section and the default CH4 and N2O 

emissions factors for kraft facilities in Table AA-1 of 

this subpart and convert the CH4 or N2O emissions to metric 

tons of CO2 equivalent by multiplying each annual CH4 and 

N2O emissions total by the appropriate global warming 

potential (GWP) factor from Table A-1 of subpart A of this 

part.

(c) For each pulp mill lime kiln located at a kraft 

or soda facility, you must determine CO2, CH4, and N2O 
360

emissions using the procedures in paragraphs (c)(1) through 

(c)(3) of this section:

(1) Calculate CO2 emissions from fossil fuel from 

direct measurement of fossil fuels consumed and default HHV 

and default emissions factors, according to the Tier 1 

Calculation Methodology for stationary combustion sources 

in §98.33(a)(1). A higher tier from §98.33(a) may be used 

to calculate fossil fuel-based CO2 emissions if the 

respective monitoring and QA/QC requirements described in 

§98.34 are met.

(2) Calculate CH4 and N2O emissions from fossil fuel 

from direct measurement of fossil fuels consumed, default

or site-specific HHV, and default emissions factors and 

convert to metric tons of CO2 equivalent according to the 

methodology for stationary combustion sources in §98.33(c); 

use the default HHV listed in Table C-1 of subpart C and 

the default CH4 and N2O emissions factors listed in Table 

AA-2 of this subpart.

(3) Biogenic CO2 emissions from conversion of CaCO3 to 

CaO are included in the biogenic CO2 estimates calculated 

for the chemical recovery furnace in paragraph (a)(3) of 

this section.

(d) For makeup chemical use, you must calculate CO2

emissions by using direct or indirect measurement of the 
361

quantity of chemicals added and ratios of the molecular 

weights of CO2 and the makeup chemicals, according to 

Equation AA-3 of this section:

CO M M kg metricton CaCO Na CO*1000 /

105.99

44

100

44 *

2 ( ) ( ) 3 2 3 











 

(Eq. AA-3)

Where:

CO2 = CO2 mass emissions from makeup chemicals 

(kilograms/yr).

M (CaCO3) = Make-up quantity of CaCO3 used for the 

reporting year (metric tons per year).

M (NaCO3) = Make-up quantity of Na2CO3 used for the 

reporting year (metric tons per year).

44 = Molecular weight of CO2.

100 = Molecular weight of CaCO3. 

105.99 = Molecular weight of Na2CO3. 

§98.274 Monitoring and QA/QC requirements. 

(a) Each facility subject to this subpart must 

quality assure the GHG emissions data according to the 

applicable requirements in §98.34. All QA/QC data must be 

available for inspection upon request. 

(b) Fuel properties needed to perform the 

calculations in Equations AA-1 and AA-2 of this subpart 

must be determined according to paragraphs (b)(1) through 

(b)(3) of this section.

(1) High heat values of black liquor must be 

determined no less than annually using T684 om–06 Gross 

Heating Value of Black Liquor, TAPPI (incorporated by 

reference, see §98.7). If measurements are performed more 
362

frequently than annually, then the high heat value used in 

Equation AA-1 of this subpart must be based on the average 

of the representative measurements made during the year.

(2) The annual mass of spent liquor solids must be 

determined using either of the methods specified in 

paragraph (b)(2)(i) or (b)(2)(ii).

(i) Measure the mass of spent liquor solids annually 

(or more frequently) using T-650 om–05 Solids Content of 

Black Liquor, TAPPI (incorporated by reference in §98.7). 

If measurements are performed more frequently than 

annually, then the mass of spent liquor solids used in 

Equation AA-1 of this subpart must be based on the average 

of the representative measurements made during the year. 

(ii) Determine the annual mass of spent liquor solids 

based on records of measurements made with an online 

measurement system that determines the mass of spent liquor 

solids fired in a chemical recovery furnace or chemical 

recovery combustion unit.

(3) Carbon analyses for spent pulping liquor must be 

determined no less than annually using ASTM D5373-08 

Standard Test Methods for Instrumental Determination of 

Carbon, Hydrogen, and Nitrogen in Laboratory Samples of 

Coal (incorporated by reference, see §98.7). If 

measurements using ASTM D5373-08 are performed more 
363

frequently than annually, then the spent pulping liquor 

carbon content used in Equation AA-2 of this subpart must 

be based on the average of the representative measurements 

made during the year.

(c) Each facility must keep records that include a 

detailed explanation of how company records of measurements 

are used to estimate GHG emissions. The owner or operator 

must also document the procedures used to ensure the 

accuracy of the measurements of fuel, spent liquor solids, 

and makeup chemical usage, including, but not limited to 

calibration of weighing equipment, fuel flow meters, and 

other measurement devices. The estimated accuracy of 

measurements made with these devices must be recorded and 

the technical basis for these estimates must be provided. 

The procedures used to convert spent pulping liquor flow 

rates to units of mass (i.e., spent liquor solids firing 

rates) also must be documented. 

(d) Records must be made available upon request for 

verification of the calculations and measurements.

§98.275 Procedures for estimating missing data.

A complete record of all measured parameters used in 

the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions during unit 
364

operation or if a required sample is not taken), a 

substitute data value for the missing parameter shall be 

used in the calculations, according to the requirements of 

paragraphs (a) through (c) of this section:

(a) There are no missing data procedures for 

measurements of heat content and carbon content of spent 

pulping liquor. A re-test must be performed if the data 

from any annual measurements are determined to be invalid.

(b) For missing measurements of the mass of spent 

liquor solids or spent pulping liquor flow rates, use the 

lesser value of either the maximum mass or fuel flow rate 

for the combustion unit, or the maximum mass or flow rate 

that the fuel meter can measure.

(c) For the use of makeup chemicals (carbonates), the 

substitute data value shall be the best available estimate 

of makeup chemical consumption, based on available data 

(e.g., past accounting records, production rates). The 

owner or operator shall document and keep records of the 

procedures used for all such estimates.

§98.276 Data reporting requirements. 

In addition to the information required by §98.3(c)

and the applicable information required by §98.36, each 

annual report must contain the information in paragraphs 

(a) through (k) of this section as applicable:
365

(a) Annual emissions of CO2, biogenic CO2, CH4, 

biogenic CH4 N2O, and biogenic N2O (metric tons per year).

(b) Annual quantities fossil fuels by type used in 

chemical recovery furnaces and chemical recovery combustion 

units in short tons for solid fuels, gallons for liquid 

fuels and scf for gaseous fuels.

(c) Annual mass of the spent liquor solids combusted 

(short tons per year), and basis for determining the annual 

mass of the spent liquor solids combusted (whether based on 

T650 om-05 Solids Content of Black Liquor, TAPPI 

(incorporated by reference, see §98.7) or an online 

measurement system).

(d) The high heat value (HHV) of the spent liquor 

solids used in Equation AA-1 of this subpart (mmBtu per 

kilogram).

(e) The default emission factor for CO2, CH4, or N2O, 

used in Equation AA-1 of this subpart (kg CO2, CH4, or N2O 

per mmBtu).

(f) The carbon content (CC) of the spent liquor 

solids, used in Equation AA-2 of this subpart (percent by 

weight, expressed as a decimal fraction, e.g., 95% = 0.95).

(g) Annual quantities of fossil fuels by type used in 

pulp mill lime kilns in short tons for solid fuels, gallons 

for liquid fuels and scf for gaseous fuels.
366

(h) Make-up quantity of CaCO3 used for the reporting 

year (metric tons per year) used in Equation AA-3 of this 

subpart. 

(i) Make-up quantity of Na2CO3 used for the reporting 

year (metric tons per year) used in Equation AA-3 of this 

subpart.

(j) Annual steam purchases(pounds of steam per year).

(k) Annual production of pulp and/or paper products 

produced (metric tons).

§98.277 Records that must be retained. 

In addition to the information required by §98.3(g), 

you must retain the records in paragraphs (a) through (f) 

of this section. 

(a) GHG emission estimates (including separate 

estimates of biogenic CO2) for each emissions source listed 

under §98.270(b).

(b) Annual analyses of spent pulping liquor HHV for 

each chemical recovery furnace at kraft and soda 

facilities.

(c) Annual analyses of spent pulping liquor carbon 

content for each chemical recovery combustion unit at a 

sulfite or semichemical pulp facility.

(d) Annual quantity of spent liquor solids combusted 

in each chemical recovery furnace and chemical recovery 
367

combustion unit, and the basis for detemining the annual 

quantity of the spent liquor solids combusted (whether 

based on T650 om–05 Solids Content of Black Liquor, TAPPI

(incorporated by reference, see §98.7) or an online 

measurement system). If an online measurement system is 

used, you must retain records of the calaulations used to 

determine the annual quantity of spent liquor solids 

combusted from the continuous measurements.

(e) Annual steam purchases.

(f) Annual quantities of makeup chemicals used.

§98.278 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part. 

Table AA-1 of Subpart AA—Kraft Pulping Liquor Emissions 

Factors for Biomass-Based CO2, CH4, and N2O.

Wood Furnish

Biomass-Based Emissions Factors 

(kg/mmBtu HHV)

CO2

a

CH4 N2O

North American 

Softwood

94.4 0.030 0.005

North American 

Hardwood

93.7

Bagasse 95.5

Bamboo 93.7

Straw 95.1

a Includes emissions from both the recovery furnace and pulp mill lime 

kiln.

Table AA-2 of Subpart AA—Kraft Lime Kiln and Calciner 

Emissions Factors for Fossil Fuel-Based CH4 and N2O

Fuel

Fossil Fuel-Based Emissions Factors (kg/mmBtu HHV)

Kraft Lime Kilns Kraft Calciners

CH4 N2O CH4 N2O

Residual 

Oil 0.0027 0 0.0027 0.0003
368

Distillate 

Oil

0.0004

Natural Gas 0.0001

Biogas 0.0001

Petroleum 

coke

NAa NAa

a. Emission factors for kraft calciners are not available.

Subpart OO—Suppliers of Industrial Greenhouse Gases

§98.410 Definition of the source category.

(a) The industrial gas supplier source category 

consists of any facility that produces a fluorinated GHG or 

nitrous oxide, any bulk importer of fluorinated GHGs or 

nitrous oxide, and any bulk exporter of fluorinated GHGs or 

nitrous oxide. 

(b) To produce a fluorinated GHG means to manufacture 

a fluorinated GHG from any raw material or feedstock 

chemical. Producing a fluorinated GHG includes the 

manufacture of a fluorinated GHG as an isolated 

intermediate for use in a process that will result in its 

transformation either at or outside of the production 

facility. Producing a fluorinated GHG also includes the 

creation of a fluorinated GHG (with the exception of HFC23) that is captured and shipped off site for any reason, 

including destruction. Producing a fluorinated GHG does 

not include the reuse or recycling of a fluorinated GHG, 

the creation of HFC-23 during the production of HCFC-22, 

the creation of intermediates that are created and 
369

transformed in a single process with no storage of the 

intermediates, or the creation of fluorinated GHGs that are 

released or destroyed at the production facility before the 

production measurement at §98.414(a). 

(c) To produce nitrous oxide means to produce nitrous 

oxide by thermally decomposing ammonium nitrate (NH4NO3). 

Producing nitrous oxide does not include the reuse or 

recycling of nitrous oxide or the creation of by-products 

that are released or destroyed at the production facility. 

§98.411 Reporting threshold.

Any supplier of industrial greenhouse gases who meets 

the requirements of §98.2(a)(4) must report GHG emissions.

§98.412 GHGs to report.

You must report the GHG emissions that would result 

from the release of the nitrous oxide and each fluorinated 

GHG that you produce, import, export, transform, or destroy 

during the calendar year. 

§98.413 Calculating GHG emissions.

(a) Calculate the total mass of each fluorinated GHG 

or nitrous oxide produced annually, except for amounts that 

are captured solely to be shipped off site for destruction, 

by using Equation OO-1 of this section: 





n

p

P Pp

1

(Eq. OO-1)
370

P = Mass of fluorinated GHG or nitrous oxide produced 

annually. 

Pp = Mass of fluorinated GHG or nitrous oxide produced 

over the period “p”.

(b) Calculate the total mass of each fluorinated GHG 

or nitrous oxide produced over the period “p” by using 

Equation OO-2 of this section: 

Pp  Op U p (Eq. OO-2)

Where:

Pp = Mass of fluorinated GHG or nitrous oxide produced 

over the period “p” (metric tons).

Op = Mass of fluorinated GHG or nitrous oxide that is 

measured coming out of the production process 

over the period p(metric tons).

Up = Mass of used fluorinated GHG or nitrous oxide 

that is added to the production process upstream 

of the output measurement over the period “p” 

(metric tons). 

(c) Calculate the total mass of each fluorinated GHG 

or nitrous oxide transformed by using Equation OO-3 of this 

section:

T  FT* ET (Eq. OO-3)

Where:

T = Mass of fluorinated GHG or nitrous oxide 

transformed annually (metric tons).

FT = Mass of fluorinated GHG fed into the transformation 

process annually (metric tons).

ET = The fraction of the fluorinated GHG or nitrous 

oxide fed into the transformation process that is 

transformed in the process (metric tons).

(d) Calculate the total mass of each fluorinated GHG 

destroyed by using Equation OO-4 of this section:
371

D  FD* DE (Eq. OO-4)

Where:

D = Mass of fluorinated GHG destroyed annually 

(metric tons).

FD = Mass of fluorinated GHG fed into the destruction 

device annually (metric tons).

DE = Destruction efficiency of the destruction device 

(fraction).

§98.414 Monitoring and QA/QC requirements. 

(a) The mass of fluorinated GHGs or nitrous oxide 

coming out of the production process shall be measured 

using flowmeters, weigh scales, or a combination of 

volumetric and density measurements with an accuracy and 

precision of one percent of full scale or better. If the 

measured mass includes more than one fluorinated GHG, the 

concentrations of each of the fluorinated GHGs, other than 

low-concentration constituents, shall be measured as set 

forth in paragraph (n) of this section. For each 

fluorinated GHG, the mean of the concentrations of that 

fluorinated GHG (mass fraction) measured under paragraph 

(n) of this section shall be multiplied by the mass 

measurement to obtain the mass of that fluorinated GHG 

coming out of the production process.

(b) The mass of any used fluorinated GHGs or used 

nitrous oxide added back into the production process 

upstream of the output measurement in paragraph (a) of this 
372

section shall be measured using flowmeters, weigh scales, 

or a combination of volumetric and density measurements 

with an accuracy and precision of one percent of full scale 

or better. If the mass in paragraph (a) of this section is

measured by weighing containers that include returned heels 

as well as newly produced fluorinated GHGs, the returned 

heels shall be considered used fluorinated GHGs for 

purposes of this paragraph (b) of this section and 

§98.413(b). 

(c) The mass of fluorinated GHGs or nitrous oxide fed 

into the transformation process shall be measured using 

flowmeters, weigh scales, or a combination of volumetric 

and density measurements with an accuracy and precision of 

one percent of full scale or better. 

(d) The fraction of the fluorinated GHGs or nitrous 

oxide fed into the transformation process that is actually 

transformed shall be estimated considering yield 

calculations or quantities of unreacted fluorinated GHGs or 

nitrous oxide permanently removed from the process and 

recovered, destroyed, or emitted. 

(e) The mass of fluorinated GHG or nitrous oxide sent 

to another facility for transformation shall be measured 

using flowmeters, weigh scales, or a combination of 
373

volumetric and density measurements with an accuracy and 

precision of one percent of full scale or better. 

(f) The mass of fluorinated GHG sent to another 

facility for destruction shall be measured using 

flowmeters, weigh scales, or a combination of volumetric 

and density measurements with an accuracy and precision of 

one percent of full scale or better. If the measured mass 

includes more than trace concentrations of materials other 

than the fluorinated GHG, the concentration of the 

fluorinated GHG shall be estimated considering current or 

previous representative concentration measurements and 

other relevant process information. This concentration 

(mass fraction) shall be multiplied by the mass measurement 

to obtain the mass of the fluorinated GHG sent to another 

facility for destruction. 

(g) You must estimate the share of the mass of 

fluorinated GHGs in paragraph (f) of this section that is 

comprised of fluorinated GHGs that are not included in the 

mass produced in §98.413(a) because they are removed from 

the production process as by-products or other wastes.

(h) You must measure the mass of each fluorinated GHG 

that is fed into the destruction device and that was 

previously produced as defined at §98.410(b). Such 

fluorinated GHGs include but are not limited to quantities 
374

that are shipped to the facility by another facility for 

destruction and quantities that are returned to the 

facility for reclamation but are found to be irretrievably 

contaminated and are therefore destroyed. You must use

flowmeters, weigh scales, or a combination of volumetric 

and density measurements with an accuracy and precision of 

one percent of full scale or better. If the measured mass 

includes more than trace concentrations of materials other 

than the fluorinated GHG being destroyed, you must estimate 

the concentrations of fluorinated GHG being destroyed 

considering current or previous representative 

concentration measurements and other relevant process 

information. You must multiply this concentration (mass 

fraction) by the mass measurement to obtain the mass of the 

fluorinated GHG destroyed.

(i) Very small quantities of fluorinated GHGs that 

are difficult to measure because they are entrained in 

other media such as destroyed filters and destroyed sample 

containers are exempt from paragraphs (f) and (h) of this 

section. 

(j) [Reserved]

(k) For purposes of Equation OO-4 of this subpart, 

the destruction efficiency can be equated to the 

destruction efficiency determined during a previous 
375

performance test of the destruction device or, if no 

performance test has been done, the destruction efficiency 

provided by the manufacturer of the destruction device. 

(l) In their estimates of the mass of fluorinated 

GHGs destroyed, fluorinated GHG production facilities that 

destroy fluorinated GHGs shall account for any temporary 

reductions in the destruction efficiency that result from 

any startups, shutdowns, or malfunctions of the destruction 

device, including departures from the operating conditions 

defined in state or local permitting requirements and/or 

oxidizer manufacturer specifications.

(m) Calibrate all flow meters, weigh scales, and 

combinations of volumetric and density measures that are 

used to measure or calculate quantities that are to be 

reported under this subpart prior to the first year for 

which GHG emissions are reported under this part. 

Calibrations performed prior to the effective date of this 

rule satisfy this requirement. Recalibrate all flow 

meters, weigh scales, and combinations of volumetric and 

density measures at the minimum frequency specified by the 

manufacturer. Use NIST-traceable standards and suitable 

methods published by a consensus standards organization 

(e.g., ASTM, ASME, ISO, or others).
376

(n) If the mass coming out of the production process 

includes more than one fluorinated GHG, you shall measure 

the concentrations of all of the fluorinated GHGs, other 

than low-concentration constituents, as follows:

(1) Analytical Methods. Use a quality-assured 

analytical measurement technology capable of detecting the 

analyte of interest at the concentration of interest and 

use a procedure validated with the analyte of interest at 

the concentration of interest. Where standards for the 

analyte are not available, a chemically similar surrogate 

may be used. Acceptable analytical measurement 

technologies include but are not limited to gas 

chromatography (GC) with an appropriate detector, infrared 

(IR), fourier transform infrared (FTIR), and nuclear 

magnetic resonance (NMR). Acceptable methods include EPA 

Method 18 in Appendix A-1 of 40 CFR part 60; EPA Method 320 

in Appendix A of 40 CFR part 63; the Protocol for Measuring 

Destruction or Removal Efficiency (DRE) of Fluorinated 

Greenhouse Gas Abatement Equipment in Electronics 

Manufacturing, Version 1, EPA-430-R-10-003, (March 2010)

(incorporated by reference, see §98.7); ASTM D6348-03 

Standard Test Method for Determination of Gaseous Compounds 

by Extractive Direct Interface Fourier Transform Infrared 

(FTIR) Spectroscopy (incorporated by reference, see §98.7); 
377

or other analytical methods validated using EPA Method 301 

in Appendix A of 40 CFR part 63 or some other 

scientifically sound validation protocol. The validation 

protocol may include analytical technology manufacturer 

specifications or recommendations. 

(2) Documentation in GHG Monitoring Plan. Describe 

the analytical method(s) used under paragraph (n)(1) of 

this section in the site GHG Monitoring Plan as required 

under §98.3(g)(5). At a minimum, include in the 

description of the method a description of the analytical 

measurement equipment and procedures, quantitative 

estimates of the method’s accuracy and precision for the 

analytes of interest at the concentrations of interest, as 

well as a description of how these accuracies and 

precisions were estimated, including the validation 

protocol used. 

(3) Frequency of measurement. Perform the 

measurements at least once by [INSERT DATE 60 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER] if the 

fluorinated GHG product is being produced on [INSERT DATE 

OF PUBLICATION IN THE FEDERAL REGISTER]. Perform the 

measurements within 60 days of commencing production of any 

fluorinated GHG product that was not being produced on 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 
378

Repeat the measurements if an operational or process change 

occurs that could change the identities or significantly 

change the concentrations of the fluorinated GHG 

constituents of the fluorinated GHG product. Complete the 

repeat measurements within 60 days of the operational or 

process change. 

(4) Measure all product grades. Where a fluorinated 

GHG is produced at more than one purity level (e.g., 

pharmaceutical grade and refrigerant grade), perform the 

measurements for each purity level.

(5) Number of samples. Analyze a minimum of three 

samples of the fluorinated GHG product that have been drawn 

under conditions that are representative of the process 

producing the fluorinated GHG product. If the relative 

standard deviation of the measured concentrations of any of 

the fluorinated GHG constituents (other than lowconcentration constituents) is greater than or equal to 15 

percent, draw and analyze enough additional samples to 

achieve a total of at least six samples of the fluorinated 

GHG product.

(o) All analytical equipment used to determine the 

concentration of fluorinated GHGs, including but not 

limited to gas chromatographs and associated detectors, IR, 

FTIR and NMR devices, shall be calibrated at a frequency 
379

needed to support the type of analysis specified in the 

site GHG Monitoring Plan as required under §98.414(n) and 

§98.3(g)(5) of this part. Quality assurance samples at the 

concentrations of concern shall be used for the 

calibration. Such quality assurance samples shall consist 

of or be prepared from certified standards of the analytes 

of concern where available; if not available, calibration 

shall be performed by a method specified in the GHG 

Monitoring Plan. 

(p) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

monitoring requirements of this section.

(q) Low-concentration constituents are exempt from 

the monitoring and QA/QC requirements of this section.

§98.415 Procedures for estimating missing data. 

(a) A complete record of all measured parameters used 

in the GHG emissions calculations is required. Therefore, 

whenever a quality-assured value of a required parameter is 

unavailable (e.g., if a meter malfunctions), a substitute 

data value for the missing parameter shall be used in the 

calculations, according to paragraph (b) of this section.

(b) For each missing value of the mass produced, fed 

into the production process (for used material being 

reclaimed), fed into the transformation process, fed into 
380

destruction devices, sent to another facility for 

transformation, or sent to another facility for 

destruction, the substitute value of that parameter shall 

be a secondary mass measurement where such a measurement is 

available. For example, if the mass produced is usually 

measured with a flowmeter at the inlet to the day tank and 

that flowmeter fails to meet an accuracy or precision test, 

malfunctions, or is rendered inoperable, then the mass 

produced may be estimated by calculating the change in 

volume in the day tank and multiplying it by the density of 

the product. Where a secondary mass measurement is not 

available, the substitute value of the parameter shall be 

an estimate based on a related parameter. For example, if 

a flowmeter measuring the mass fed into a destruction 

device is rendered inoperable, then the mass fed into the 

destruction device may be estimated using the production 

rate and the previously observed relationship between the 

production rate and the mass flow rate into the destruction 

device. 

§98.416 Data reporting requirements.

In addition to the information required by §98.3(c), 

each annual report must contain the following information:

(a) Each fluorinated GHG or nitrous oxide production 

facility shall report the following information: 
381

(1) Mass in metric tons of each fluorinated GHG or 

nitrous oxide produced at that facility by process, except 

for amounts that are captured solely to be shipped off site 

for destruction. 

(2) Mass in metric tons of each fluorinated GHG or 

nitrous oxide transformed at that facility, by process. 

(3) Mass in metric tons of each fluorinated GHG that 

is destroyed at that facility and that was previously

produced as defined at §98.410(b). Quantities to be 

reported under this paragraph (a)(3) of this section 

include but are not limited to quantities that are shipped 

to the facility by another facility for destruction and

quantities that are returned to the facility for 

reclamation but are found to be irretrievably contaminated 

and are therefore destroyed. 

(4) [Reserved]

(5) Total mass in metric tons of each fluorinated GHG 

or nitrous oxide sent to another facility for

transformation.

(6) Total mass in metric tons of each fluorinated GHG 

sent to another facility for destruction, except 

fluorinated GHGs that are not included in the mass produced 

in §98.413(a) because they are removed from the production 

process as by-products or other wastes. Quantities to be 
382

reported under this paragraph (a)(6) could include, for 

example, fluorinated GHGs that are returned to the facility 

for reclamation but are found to be irretrievably 

contaminated and are therefore sent to another facility for 

destruction.

(7) Total mass in metric tons of each fluorinated GHG 

that is sent to another facility for destruction and that 

is not included in the mass produced in §98.413(a) because 

it is removed from the production process as a byproduct or 

other waste.

(8) Total mass in metric tons of each reactant fed 

into the F-GHG or nitrous oxide production process, by 

process.

(9) Total mass in metric tons of the reactants, byproducts, and other wastes permanently removed from the FGHG or nitrous oxide production process, by process. 

(10) For transformation processes that do not produce 

an F-GHG or nitrous oxide, mass in metric tons of any 

fluorinated GHG or nitrous oxide fed into the 

transformation process, by process.

(11) Mass in metric tons of each fluorinated GHG that 

is fed into the destruction device and that was previously 

produced as defined at §98.410(b). Quantities to be 

reported under this paragraph (a)(11) of this section 
383

include but are not limited to quantities that are shipped 

to the facility by another facility for destruction and 

quantities that are returned to the facility for 

reclamation but are found to be irretrievably contaminated 

and are therefore destroyed.

(12) Mass in metric tons of each fluorinated GHG or 

nitrous oxide that is measured coming out of the production 

process, by process.

(13) Mass in metric tons of each used fluorinated 

GHGs or nitrous oxide added back into the production 

process (e.g., for reclamation), including returned heels 

in containers that are weighed to measure the mass in 

§98.414(a), by process.

(14) Names and addresses of facilities to which any 

nitrous oxide or fluorinated GHGs were sent for 

transformation, and the quantities (metric tons) of nitrous 

oxide and of each fluorinated GHG that were sent to each 

for transformation.

(15) Names and addresses of facilities to which any 

fluorinated GHGs were sent for destruction, and the 

quantities (metric tons) of nitrous oxide and of each 

fluorinated GHG that were sent to each for destruction.

(16) Where missing data have been estimated pursuant 

to §98.415, the reason the data were missing, the length of 
384

time the data were missing, the method used to estimate the 

missing data, and the estimates of those data. 

(b) A fluorinated GHG production facility or importer 

that destroys fluorinated GHGs shall submit a one-time 

report containing the following information:

(1) Destruction efficiency (DE) of each destruction 

unit. 

(2) Methods used to determine the destruction 

efficiency.

(3) Methods used to record the mass of fluorinated 

GHG destroyed.

(4) Chemical identity of the fluorinated GHG(s) used 

in the performance test conducted to determine DE.

(5) Name of all applicable federal or state 

regulations that may apply to the destruction process. 

(6) If any process changes affect unit destruction 

efficiency or the methods used to record mass of 

fluorinated GHG destroyed, then a revised report must be 

submitted to reflect the changes. The revised report must 

be submitted to EPA within 60 days of the change.

(c) Each bulk importer of fluorinated GHGs or nitrous 

oxide shall submit an annual report that summarizes its

imports at the corporate level, except for shipments 

including less than twenty-five kilograms of fluorinated 
385

GHGs or nitrous oxide, transshipments, and heels that meet 

the conditions set forth at §98.417(e). The report shall 

contain the following information for each import: 

(1) Total mass in metric tons of nitrous oxide and 

each fluorinated GHG imported in bulk, including each 

fluorinated GHG constituent of the fluorinated GHG product 

that makes up between 0.5 percent and 100 percent of the 

product by mass.

(2) Total mass in metric tons of nitrous oxide and 

each fluorinated GHG imported in bulk and sold or 

transferred to persons other than the importer for use in 

processes resulting in the transformation or destruction of 

the chemical.

(3) Date on which the fluorinated GHGs or nitrous 

oxide were imported.

(4) Port of entry through which the fluorinated GHGs 

or nitrous oxide passed. 

(5) Country from which the imported fluorinated GHGs 

or nitrous oxide were imported.

(6) Commodity code of the fluorinated GHGs or nitrous 

oxide shipped. 

(7) Importer number for the shipment. 

(8) Total mass in metric tons of each fluorinated GHG 

destroyed by the importer.
386

(9) If applicable, the names and addresses of the 

persons and facilities to which the nitrous oxide or 

fluorinated GHGs were sold or transferred for 

transformation, and the quantities (metric tons) of nitrous 

oxide and of each fluorinated GHG that were sold or 

transferred to each facility for transformation.

(10) If applicable, the names and addresses of the 

persons and facilities to which the nitrous oxide or 

fluorinated GHGs were sold or transferred for destruction, 

and the quantities (metric tons) of nitrous oxide and of 

each fluorinated GHG that were sold or transferred to each 

facility for destruction.

(d) Each bulk exporter of fluorinated GHGs or nitrous 

oxide shall submit an annual report that summarizes its

exports at the corporate level, except for shipments 

including less than twenty-five kilograms of fluorinated 

GHGs or nitrous oxide, transshipments, and heels. The 

report shall contain the following information for each 

export: 

(1) Total mass in metric tons of nitrous oxide and 

each fluorinated GHG exported in bulk.

(2) Names and addresses of the exporter and the 

recipient of the exports.

(3) Exporter’s Employee Identification Number.
387

(4) Commodity code of the fluorinated GHGs and 

nitrous oxide shipped.

(5) Date on which, and the port from which, 

fluorinated GHGs and nitrous oxide were exported from the 

United States or its territories.

(6) Country to which the fluorinated GHGs or nitrous 

oxide were exported.

(e) By April 1, 2011, a fluorinated GHG production 

facility shall submit a one-time report describing the 

following information:

(1) The method(s) by which the producer in practice 

measures the mass of fluorinated GHGs produced, including 

the instrumentation used (Coriolis flowmeter, other 

flowmeter, weigh scale, etc.) and its accuracy and 

precision. 

(2) The method(s) by which the producer in practice 

estimates the mass of fluorinated GHGs fed into the 

transformation process, including the instrumentation used 

(Coriolis flowmeter, other flowmeter, weigh scale, etc.) 

and its accuracy and precision. 

(3) The method(s) by which the producer in practice 

estimates the fraction of fluorinated GHGs fed into the 

transformation process that is actually transformed, and 

the estimated precision and accuracy of this estimate.
388

(4) The method(s) by which the producer in practice 

estimates the masses of fluorinated GHGs fed into the 

destruction device, including the method(s) used to 

estimate the concentration of the fluorinated GHGs in the 

destroyed material, and the estimated precision and 

accuracy of this estimate. 

(5) The estimated percent efficiency of each 

production process for the fluorinated GHG produced.

(f) By March 31, 2011, all fluorinated GHG production 

facilities shall submit a one-time report that includes the 

concentration of each fluorinated GHG constituent in each 

fluorinated GHG product as measured under §98.414(n). If 

the facility commences production of a fluorinated GHG 

product that was not included in the initial report or 

performs a repeat measurement under §98.414(n) that shows 

that the identities or concentrations of the fluorinated 

GHG constituents of a fluorinated GHG product have changed, 

then the new or changed concentrations, as well as the date 

of the change, must be reflected in a revision to the 

report. The revised report must be submitted to EPA by the 

March 31st that immediately follows the measurement under 

§98.414(n).
389

(g) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

reporting requirements of this section.

(h) Low-concentration constituents are exempt from 

the reporting requirements of this section.

§98.417 Records that must be retained.

(a) In addition to the data required by §98.3(g), the 

fluorinated GHG production facility shall retain the 

following records:

(1) Dated records of the data used to estimate the 

data reported under §98.416.

(2) Records documenting the initial and periodic 

calibration of the analytical equipment (including but not 

limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, 

and volumetric and density measures used to measure the 

quantities reported under this subpart, including the 

industry standards or manufacturer directions used for 

calibration pursuant to §98.414(m) and (o).

(b) In addition to the data required by paragraph (a) 

of this section, the fluorinated GHG production facility 

that destroys fluorinated GHGs shall keep records of test 

reports and other information documenting the facility’s 

one-time destruction efficiency report and annual 

destruction device outlet reports in §98.416(b) and (e).
390

(c) In addition to the data required by §98.3(g), the 

bulk importer shall retain the following records 

substantiating each of the imports that they report:

(1) A copy of the bill of lading for the import.

(2) The invoice for the import.

(3) The U.S. Customs entry form.

(d) In addition to the data required by §98.3(g), the 

bulk exporter shall retain the following records 

substantiating each of the exports that they report:

(1) A copy of the bill of lading for the export and

(2) The invoice for the import.

(e) Every person who imports a container with a heel 

that is not reported under §98.416(c) shall keep records of 

the amount brought into the United States that document 

that the residual amount in each shipment is less than 10 

percent of the volume of the container and will:

(1) Remain in the container and be included in a 

future shipment.

(2) Be recovered and transformed.

(3) Be recovered and destroyed.

(4) Be recovered and included in a future shipment.

(f) Isolated intermediates that are produced and 

transformed at the same facility are exempt from the 

recordkeeping requirements of this section.
391

(g) Low-concentration constituents are exempt from 

the recordkeeping requirements of this section.

§98.418 Definitions.

Except as provided below, all of the terms used in 

this subpart have the same meaning given in the Clean Air 

Act and subpart A of this part. If a conflict exists 

between a definition provided in this subpart and a 

definition provided in subpart A, the definition in this 

subpart shall take precedence for the reporting 

requirements in this subpart.

Isolated intermediate means a product of a process 

that is stored before subsequent processing. An isolated 

intermediate is usually a product of chemical synthesis. 

Storage of an isolated intermediate marks the end of a 

process. Storage occurs at any time the intermediate is 

placed in equipment used solely for storage.

Low-concentration constituent means, for purposes of 

fluorinated GHG production and export, a fluorinated GHG 

constituent of a fluorinated GHG product that occurs in the 

product in concentrations below 0.1 percent by mass. For 

purposes of fluorinated GHG import, low-concentration 

constituent means a fluorinated GHG constituent of a 

fluorinated GHG product that occurs in the product in 

concentrations below 0.5 percent by mass. Low-
392

concentration constituents do not include fluorinated GHGs 

that are deliberately combined with the product (e.g., to 

affect the performance characteristics of the product).

Subpart PP—Suppliers of Carbon Dioxide

§98.420 Definition of the source category.

(a) The carbon dioxide (CO2) supplier source category 

consists of the following:

(1) Facilities with production process units that 

capture a CO2 stream for purposes of supplying CO2 for 

commercial applications or that capture and maintain 

custody of a CO2 stream in order to sequester or otherwise 

inject it underground. Capture refers to the initial 

separation and removal of CO2 from a manufacturing process 

or any other process. 

(2) Facilities with CO2 production wells that extract 

or produce a CO2 stream for purposes of supplying CO2 for 

commercial applications or that extract and maintain 

custody of a CO2 stream in order to sequester or otherwise 

inject it underground. 

(3) Importers or exporters of bulk CO2. 

(b) This source category is focused on upstream 

supply. It does not cover: 

(1) Storage of CO2 above ground or in geologic 

formations. 
393

(2) Use of CO2 in enhanced oil and gas recovery. 

(3) Transportation or distribution of CO2.

(4) Purification, compression, or processing of CO2.

(5) On-site use of CO2 captured on site. 

(c) This source category does not include CO2 imported 

or exported in equipment, such as fire estinguishers. 

§98.421 Reporting threshold.

Any supplier of CO2 who meets the requirements of 

§98.2(a)(4) of subpart A of this part must report the mass 

of CO2 captured, extracted, imported, or exported.

§98.422 GHGs to report.

(a) Mass of CO2 captured from production process 

units.

(b) Mass of CO2 extracted from CO2 production wells.

(c) Mass of CO2 imported.

(d) Mass of CO2 exported.

§98.423 Calculating CO2 Supply.

(a) Except as allowed in paragraph (b) of this 

section, calculate the annual mass of CO2 captured, 

extracted, imported, or exported through each flow meter in 

accordance with the procedures specified in either 

paragraph (a)(1) or (a)(2) of this section. If multiple 

flow meters are used, you shall calculate the annual mass 
394

of CO2 for all flow meters according to the procedures 

specified in paragraph (a)(3) of this section. 

(1) For each mass flow meter, you shall calculate 

quarterly the mass of CO2 in a CO2 stream in metric tons by 

multiplying the mass flow by the composition data, 

according to Equation PP-1 of this section. Mass flow and 

composition data measurements shall be made in accordance 

with §98.424 of this subpart.

CO2,u = CO p u

p

Qp u C 2, ,*

4

1

 ,



(Eq. PP-1)

Where: 

CO2,u = Annual mass of CO2 (metric tons) through flow 

meter u. 

CCO2,p,u = Quarterly CO2 concentration measurement in flow 

for flow meter u in quarter p (wt. %CO2).

Qp,u = Quarterly mass flow rate measurement for flow 

meter u in quarter p (metric tons). 

p = Quarter of the year.

u = Flow meter. 

(2) For each volumetric flow meter, you shall 

calculate quarterly the mass of CO2 in a CO2 stream in 

metric tons by multiplying the volumetric flow by the 

concentration and density data, according to Equation PP-2 

of this section. Volumetric flow, concentration and 

density data measurements shall be made in accordance with 

§98.424 of this section.
395

CO2,u = CO p

p

p

Qp D C 2,* *

4

1



(Eq. PP-2)

Where: 

CO2,u = Annual mass of CO2 (metric tons) through flow 

meter u. 

CCO2,p = Quarterly CO2 concentration measurement in flow 

for flow meter u in quarter p (wt. % CO2).

Qp = Quarterly volumetric flow rate measurement for 

flow meter u in quarter p (standard cubic 

meters).

Dp = Quarterly CO2 stream density measurement for 

flow meter u in quarter p (metric tons per 

standard cubic meter).

p = Quarter of the year.

u = Flow meter. 

(3) To aggregate data, sum the mass of CO2 for all 

flow meters in accordance with Equation PP-3 of this 

section. 

CO2 = 

U

p 1

CO2, u (Eq. PP-3)

Where: 

CO2 = Annual mass of CO2 (metric tons) through all 

flow meters. 

CO2,u = Annual mass of CO2 (metric tons) through flow 

meter u. 

u = Flow meter. 

(b) As an alternative to paragraphs (a)(1) through 

(3) of this section for CO2 that is supplied in containers, 

calculate the annual mass of CO2 supplied in containers 
396

delivered by each CO2 stream in accordance with the 

procedures specified in either paragraph (b)(1) or (b)(2) 

of this section. If multiple CO2 streams are used to 

deliver CO2 to containers, you shall calculate the annual 

mass of CO2 supplied in containers delivered by all CO2

streams according to the procedures specified in paragraph 

(b)(3) of this section.

(1) For each CO2 stream that delivers CO2 to 

containers, for which mass is measured, you shall calculate 

CO2 supply in containers using Equation PP-1 of this 

section.

Where: 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 

CCO2,p,u = Quarterly CO2 concentration measurement of CO2

stream u that delivers CO2 to containers in 

quarter p (wt. %CO2).

Qp,u = Quarterly mass of contents supplied in all 

containers delivered by CO2 stream u in quarter 

p (metric tons). 

p = Quarter of the year.

u = CO2 stream that delivers to containers. 

(2) For each CO2 stream that delivers to containers, 

for which volume is measured, you shall calculate CO2 supply 

in containers using Equation PP-2 of this section.

Where: 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 
397

CCO2,p,u = Quarterly CO2 concentration measurement of CO2

stream u that delivers CO2 to containers in 

quarter p (vol. %CO2).

Qp = Quarterly volume of contents supplied in all 

containers delivered by CO2 stream u in quarter 

p (metric tons) (standard cubic meters).

Dp = Quarterly CO2 stream density determination for 

CO2 stream u in quarter p (metric tons per 

standard cubic meter). 

p = Quarter of the year.

u = CO2 stream that delivers to containers. 

(3) To aggregate data, sum the mass of CO2 supplied in 

containers delivered by all CO2 streams in accordance with 

Equation PP-3 of this section. 

Where: 

CO2 = Annual mass of CO2 (metric tons) supplied in 

containers delivered by all CO2 streams. 

CO2,u = Annual mass of CO2 (metric tons) supplied in 

containers delivered by CO2 stream u. 

u = CO2 stream that delivers to containers. 

(c) Importers or exporters that import or export CO2

in containers shall calculate the total mass of CO2 imported 

or exported in metric tons based on summing the mass in 

each CO2 container using weigh bills, scales, or load cells 

according to Equation PP-4 of this section.

CO2 = Q

I

p

1

(Eq. PP-4)

Where: 

CO2 = Annual mass of CO2 (metric tons). 
398

Q = Annual mass in all CO2 containers imported or 

exported during the reporting year (metric 

tons).

§98.424 Monitoring and QA/QC requirements.

(a) Determination of quantity.

(1) Reporters following the procedures in paragraph 

(a) of §98.423 shall determine quantity using a flow meter 

or meters located in accordance with this paragraph. 

(i) If the CO2 stream is segregated such that only a 

portion is captured for commercial application or for 

injection, you must locate the flow meter after the point 

of segregation.

(ii) Reporters that have a mass flow meter or 

volumetric flow meter installed to measure the flow of a CO2 

stream that meets the requirements of paragraph (i) of this 

section shall base calculations in §98.423 of this subpart 

on the installed mass flow or volumetric flow meters. 

(iii) Reporters that do not have a mass flow meter or 

volumetric flow meter installed to measure the flow of the 

CO2 stream that meets the requirements of paragraph (i) of 

this section shall base calculations in §98.423 of this 

subpart on the flow of gas transferred off site using a 

mass flow meter or a volumetric flow meter located at the 

point of off-site transfer.
399

(2) Reporters following the procedures in paragraph 

(b) of §98.423 shall determine quantity in accordance with 

this paragraph. 

(i) Reporters that supply CO2 in containers using 

weigh bills, scales, or load cells shall measure the mass 

of contents of each CO2 container to which the CO2 stream 

delivered, sum the mass of contents supplied in all 

containers to which the CO2 stream delivered during each 

quarter, sample the CO2 stream delivering CO2 to containers 

on a quarterly basis to determine the composition of the CO2

stream, and apply Equation PP-1.

(ii) Reporters that supply CO2 in containers using 

loaded container volumes shall measure the volume of 

contents of each CO2 container to which the CO2 stream 

delivered, sum the volume of contents supplied in all 

containers to which the CO2 stream delivered during each 

quarter, sample the CO2 stream on a quarterly basis to 

determine the composition of the CO2 stream, determine the 

density quarterly, and apply Equation PP-2.

(3) Importers or exporters that import or export CO2

in containers shall measure the mass in each CO2 container 

using weigh bills, scales, or load cells and sum the mass 

in all containers imported or exported during the reporting 

year.
400

(4) All flow meters, scales, and load cells used to 

measure quantities that are reported in §98.423 of this 

subpart shall be operated and calibrated according to the 

following procedure: 

(i) You shall use an appropriate standard method 

published by a consensus-based standards organization if 

such a method exists. Consensus-based standards 

organizations include, but are not limited to, the 

following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(ii) Where no appropriate standard method developed 

by a consensus-based standards organization exists, you 

shall follow industry standard practices.

(iii) You must ensure that any flow meter 

calibrations performed are NIST traceable.

(5) Reporters using Equation PP-2 of this subpart 

shall determine the density of the CO2 stream on a quarterly 

basis in order to calculate the mass of the CO2 stream 

according to one of the following procedures: 

(i) You shall use an appropriate standard method 

published by a consensus-based standards organization to 
401

measure density if such a method exists. Consensus-based 

standards organizations include, but are not limited to, 

the following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association 

(AGA), the American Society of Mechanical Engineers (ASME), 

the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB). 

(ii) You shall follow industry standard practices.

(b) Determination of concentration.

(1) Reporters using Equation PP-1 or PP-2 of this 

subpart shall sample the CO2 stream on a quarterly basis to 

determine the composition of the CO2 stream. 

(2) Methods to measure the composition of the CO2 

stream must conform to applicable chemical analytical 

standards. Acceptable methods include U.S. Food and Drug 

Administration food-grade specifications for CO2 (see 21 CFR 

184.1240) and ASTM standard E1747-95(Reapproved 2005) 

Standard Guide for Purity of Carbon Dioxide Used in 

Supercritical Fluid Applications (incorporated by 

reference, see §98.7 of subpart A of this part).

(c) If you measure the flow of the CO2 stream with a 

volumetric flow meter, you shall convert all measured 

volumes of carbon dioxide to the following standard 

industry temperature and pressure conditions: standard 
402

cubic meters at a temperature of 60 degrees Fahrenheit and 

at an absolute pressure of 1 atmosphere. If you apply the 

density value for CO2 at standard conditions, you must use 

must use 0.0018704 metric tons per standard cubic meter.

§98.425 Procedures for estimating missing data.

(a) Whenever the quality assurance procedures in 

§98.424(a)(2) of this subpart cannot be followed to measure 

quarterly mass flow or volumetric flow of CO2, the most 

appropriate of the following missing data procedures shall 

be followed:

(1) A quarterly CO2 mass flow or volumetric flow value 

that is missing may be substituted with a quarterly value 

measured during another quarter of the current reporting 

year. 

(2) A quarterly CO2 mass flow or volumetric flow value 

that is missing may be substituted with a quarterly value 

measured during the same quarter from the past reporting 

year. 

(3) If a mass or volumetric flow meter is installed 

to measure the CO2 stream, you may substitute data from a 

mass or volumetric flow meter measuring the CO2 stream 

transferred for any period during which the installed meter 

is inoperable.
403

(4) The mass or volumetric flow used for purposes of 

product tracking and billing according to the reporter’s 

established procedures may be substituted for any period 

during which measurement equipment is inoperable.

(b) Whenever the quality assurance procedures in 

§98.424(b) of this subpart cannot be followed to determine 

concentration of the CO2 stream, the most appropriate of the 

following missing data procudures shall be followed:

(1) A quarterly concentration value that is missing 

may be substituted with a quarterly value measured during 

another quarter of the current reporting year. 

(2) A quarterly concentration value that is missing 

may be substituted with a quarterly value measured during 

the same quarter from the previous reporting year.

(3) The concentration used for purposes of product 

tracking and billing according to the reporter’s 

established procedures may be substituted for any quarterly 

value.

(c) Missing data on density of the CO2 stream shall be 

substituted with quarterly or annual average values from 

the previous calendar year.

(d) Whenever the quality assurance procedures in 

§98.424(a)(2) of this subpart cannot be followed to measure 

quarterly quantity of CO2 in containers, the most 
404

appropriate of the following missing data procedures shall 

be followed:

(1) A quarterly quantity of CO2 in containers that is 

missing may be substituted with a quarterly value measured 

during another representative quarter of the current 

reporting year. 

(2) A quarterly quantity of CO2 in containers that is 

missing may be substituted with a quarterly value measured 

during the same quarter from the past reporting year. 

(3) The quarterly quantity of CO2 in containers 

recorded for purposes of product tracking and billing 

according to the reporter’s established procedures may be 

substituted for any period during which measurement 

equipment is inoperable.

§98.426 Data reporting requirements.

In addition to the information required by §98.3(c) of 

subpart A of this part, the annual report shall contain the 

following information, as applicable:

(a) If you use Equation PP-1 of this subpart, report 

the following information for each mass flow meter or CO2

stream that delivers CO2 to containers:

(1) Annual mass in metric tons of CO2.

(2) Quarterly mass in metric tons of CO2.

(3) Quarterly concentration of the CO2 stream.
405

(4) The standard used to measure CO2 concentration.

(5) The location of the flow meter in your process 

chain in relation to the points of CO2 stream capture, 

deyhdration, compression, and other processing. 

(b) If you use Equation PP-2 of this subpart, report 

the following information for each volumetric flow meter or 

CO2 stream that delivers CO2 to containers:

(1) Annual mass in metric tons of CO2.

(2) Quarterly volume in standard cubic meters of CO2.

(3) Quarterly concentration of the CO2 stream. 

(4) Quarterly density of the CO2 stream.

(5) The method used to measure density.

(6) The standard used to measure CO2 concentration.

(7) The location of the flow meter in your process 

chain in relation to the points of CO2 stream capture, 

deyhdration, compression, and other processing. 

(c) If you use Equation PP-3 of this subpart report 

the annual CO2 mass in metric tons from all flow meters and 

CO2 streams that delivers CO2 to containers.

(d) If you use Equation PP-4 of this subpart, report 

at the corporate level the annual mass of CO2 in metric tons 

in all CO2 containers that are imported or exported.

(e) Each reporter shall report the following 

information:
406

(1) The type of equipment used to measure the total 

flow of the CO2 stream or the total mass or volume in CO2

containers.

(2) The standard used to operate and calibrate the 

equipment reported in (e)(1) of this section.

(3) The number of days in the reporting year for 

which substitute data procedures were used for the 

following purpose:

(i) To measure quantity.

(ii) To measure concentration.

(iii) To measure density.

(f) Report the aggregated annual quantity of CO2 in 

metric tons that is transferred to each of the following 

end use applications, if known:

(i) Food and beverage.

(ii) Industrial and municipal water/wastewater

treatment.

(iii) Metal fabrication, including welding and 

cutting.

(iv) Greenhouse uses for plant growth.

(v) Fumigants (e.g., grain storage) and herbicides.

(vi) Pulp and paper.

(vii) Cleaning and solvent use.

(viii) Fire fighting.
407

(ix) Transportation and storage of explosives.

(x) Enhanced oil and natural gas recovery.

(xi) Long-term storage (sequestration).

(xii) Research and development.

(xiii) Other.

(g) Each production process unit that captures a CO2 

stream for purposes of supplying CO2 for commercial 

applications or in order to sequester or otherwise inject 

it underground when custody of the CO2 is maintained shall 

report the percentage of that stream, if any, that is 

biomass-based during the reporting year.

§98.427 Records that must be retained.

In addition to the records required by §98.3(g) of 

subpart A of this part, you must retain the records 

specified in paragraphs (a) through (c) of this section, as 

applicable.

(a) The owner or operator of a facility containing 

production process units must retain quarterly records of 

captured or transferred CO2 streams and composition. 

(b) The owner or operator of a CO2 production well 

facility must maintain quarterly records of the mass flow 

or volumetric flow of the extracted or transferred CO2

stream and concentration and density if volumetric flow 

meters are used. 
408

(c) Importers or exporters of CO2 must retain annual 

records of the mass flow, volumetric flow, and mass of CO2

imported or exported.

§98.428 Definitions.

All terms used in this subpart have the same meaning 

given in the Clean Air Act and subpart A of this part.